<TABLE>
<CAPTION>

                                                            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 JUNE 30, 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) 716-1000
</TABLE>

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 July 31, 2003 was 395,001,853.

<PAGE>
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<CAPTION>

                               AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                           INDEX TO QUARTERLY REPORT ON FORM 10-Q
                                                        June 30, 2003

                                                                                                                    Page
                                                                                                                    ----
   <S>                                                                                                              <C>
   Glossary of Terms                                                                                                i - iii
   Forward-Looking Information                                                                                      iv

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

                         American Electric Power Company, Inc. and Subsidiary Companies:
                              Management's Financial Discussion and Analysis                                        A-1 - A-16
                              Consolidated Financial Statements                                                     A-17 - A-21
                              Notes to Consolidated Financial Statements                                            A-22 - A-50

                         AEP Generating Company:
                              Management's Narrative Financial Discussion and Analysis                              B-1
                              Financial Statements                                                                  B-2 - B-5

                         AEP Texas Central Company and Subsidiaries:
                              Management's Financial Discussion and Analysis                                        C-1 - C-6
                              Consolidated Financial Statements                                                     C-7 - C-11

                         AEP Texas North Company:
                              Management's Narrative Financial Discussion and Analysis                              D-1 - D-5
                              Financial Statements                                                                  D-6 - D-10

                         Appalachian Power Company and Subsidiaries:
                              Management's Financial Discussion and Analysis                                        E-1 - E-6
                              Consolidated Financial Statements                                                     E-7 - E-11

                         Columbus Southern Power Company and Subsidiaries:
                              Management's Narrative Financial Discussion and Analysis                              F-1 - F-6
                              Consolidated Financial Statements                                                     F-7 - F-11

                         Indiana Michigan Power Company and Subsidiaries:
                              Management's Financial Discussion and Analysis                                        G-1 - G-7
                              Consolidated Financial Statements                                                     G-8 - G-12

                         Kentucky Power Company:
                              Management's Narrative Financial Discussion and Analysis                              H-1 - H-5
                              Financial Statements                                                                  H-6 - H-10

                         Ohio Power Company:
                              Management's Financial Discussion and Analysis                                        I-1 - I-6
                              Financial Statements                                                                  I-7 - I-11

                         Public Service Company of Oklahoma and Subsidiary:
                              Management's Narrative Financial Discussion and Analysis                              J-1 - J-4
                              Consolidated Financial Statements                                                     J-5 - J-9

                         Southwestern Electric Power Company and Subsidiaries:
                              Management's Financial Discussion and Analysis                                        K-1 - K-5
                              Consolidated Financial Statements                                                     K-6 - K-10

                         Notes to Respective Financial Statements                                                   L-1 - L-20

       Item 4.        Controls and Procedures                                                                       M-1

   Part II.           OTHER INFORMATION
       Item 1.            Legal Proceedings                                                                         N-1
       Item 4.            Submission of Matters to a Vote of  Security Holders                                      N-2
       Item 5.            Other Information                                                                         N-4
       Item 6.            Exhibits and Reports on Form 8-K                                                          N-4
                                     (a)     Exhibits:
                                              Exhibit 12
                                              Exhibit 31.1
                                              Exhibit 31.2
                                              Exhibit 32.1
                                              Exhibit 32.2
                                     (b)     Reports on Form 8-K

   SIGNATURES                                                                                                       O-1
</TABLE>


   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.


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

               Term                                Meaning
               ----                                -------

<C>                                <C>
2004 True-up Proceeding            A filing to be made after January 10, 2004 under the Texas  Legislation to finalize the amount
                                            of stranded costs and 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 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                          Emerging  Issues Task Force Issue No.  02-3:  Issues  Involved in  Accounting  for  Derivative
                                            Contracts Held For Trading Purposes and Contracts Involved in Energy Trading and
                                            Risk Management Activities.
ERCOT                              The Electric Reliability Council of Texas.
FASB                               Financial Accounting Standards Board.
Federal EPA                        United States Environmental Protection Agency.
FERC                               Federal Energy Regulatory Commission.
FIN 45                             FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
                                            Guarantees, Including Indirect Guarantees of Indebtedness of Others"
FIN 46                             FASB Interpretation No. 46" Consolidation of Variable Interest Entities"
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.
LPSC                               Louisiana Public Service Commission
Michigan Legislation               The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
                                            customer choice of electricity supplier.
MISO                               Midwest Independent System Operator (an independent operator of transmission assets in the
                                            Midwest).
MLR                                Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool                         AEP System's Money Pool.
MPSC                               Michigan Public Service Commission.
MTM                                Mark-to-Market.
MW                                 Megawatt.
MWH                                Megawatthour.
NOx                                Nitrogen oxide.
NOx Rule                           A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including
                                            seven of the states in which AEP companies operate.
NRC                                Nuclear Regulatory Commission.
OCC                                The Corporation Commission of the State of Oklahoma.
Ohio Act                           The Ohio Electric Restructuring Act of 1999.
Ohio EPA                           Ohio Environmental Protection Agency.
OPCo                               Ohio Power Company, an AEP electric utility subsidiary.
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 Operations.
                                            ------------------------------------------
SFAS 149                           Statement of Financial Accounting Standards No. 149,
                                            Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
                                            ---------------------------------------------------------------------------
SFAS 150                           Statement of Financial Accounting Standards No. 150,
                                            Accounting for Certain Financial Instruments with Characteristics of both Liabilities
                                            -------------------------------------------------------------------------------------
                                            and Equity.
                                            ----------
SNF                                Spent Nuclear Fuel.
SPP                                Southwest Power Pool.
STP                                South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
                                            AEP electric utility subsidiary.
STPNOC                             STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
                                            its joint owners including TCC.
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)].
Tenor                              Maturity of a contract.
Texas Legislation                  Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC                                AEP Texas North Company, an AEP electric utility subsidiary [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>

     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
         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>
<TABLE>
<CAPTION>
                                       AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                             MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations
---------------------
American Electric Power Company's consolidated Net Income (Loss) by operating
segment for the quarter and year-to-date periods ended June 30, 2003 and 2002
were as follows:

                                                                   Three Months Ended                Six Months Ended
                                                                   2003           2002               2003          2002
                                                                   ----           ----               ----          ----
                                                                                       (in millions)

               <S>                                                 <C>            <C>                <C>          <C>
               Utility Operations                                  $222           $228               $750         $ 441
               Investments - Gas Operations                         (24)           (32)               (61)          (80)
               Investments - UK Operations                            3            (12)               (59)           11
               Investments - Other                                  (26)          (122)               (15)         (479)
                                                                   ----           ----               ----         -----

                          Total                                    $175           $ 62               $615         $(107)
                                                                   ====           ====               ====         =====
</TABLE>

Our Net Income is discussed below according to the operating segments listed
above.  Income Before Discontinued Operations and Cumulative Effect
for the quarter and year-to-date were affected by the weather, weak economy and
the availability of electric generation.  Year-to-date Net Income of $615
million or $1.64 per share includes $242 million (net of tax) of Income from
Cumulative Effect of Accounting Changes in the first quarter resulting from
the implementation of SFAS 143 (see Note 4) partially offset by $49 million
(net of tax) of Loss from Cumulative Effect of Accounting Changes in the first
quarter resulting from the implementation of EITF 02-3 (see Note 4) and
discontinued operations of $16 million loss (net of tax) (see Note 11).  The
loss of $107 million year-to-date 2002 includes discontinued operations of $74
million loss (net of tax) (see Note 11) and a $350 million (net of tax) charge
discussed below in the Investments - Other segment for the implementation of
SFAS 142 (see Note 4).

Utility Operations

Net Income for Utility Operations, our core business, decreased in the quarter
$6 million and increased year-to-date $309 million due to the fluctuations in
operating income along with the year-to-date adjustment for the cumulative
effect of accounting changes. Year-to-date Net Income of $750 million included
$249 million (net of tax) of Income from Cumulative Effect of Accounting Changes
in the first quarter resulting from the implementation of SFAS 143 (see Note 4)
partially offset by $11 million (net of tax) Loss from Cumulative Effect of
Accounting Changes in the first quarter resulting from the implementation of
EITF 02-3 (see Note 4). Operating income decreased in the second quarter and
increased on a year-to-date basis primarily due to:

o        Pre-tax earnings increased $59 million in the quarter and $116 million
         year-to-date resulting primarily from the non-cash earnings associated
         with the stranded cost recovery in Texas which recognizes the
         difference between the actual price received from the state-mandated
         auction of 15% of generation capacity and the earlier estimate of
         market price derived by the PUCT model. This regulatory asset is
         expected to be recovered through the 2004 true-up proceeding
         established by deregulation laws in Texas.

o        Pre-tax earnings for systems sales, transmission revenue and other
         wholesale transactions decreased $7 million in the current quarter as a
         result of our exit from trading markets where we do not own assets.
         Year-to-date pre-tax earnings increased by $66 million due to favorable
         power optimization and higher transmission volumes.

o        Retail  margins from the regulated  integrated  utilities  reduced
         pre-tax  earnings by $64 million for the quarter and $61 million
         year-to-date  due to the combined impact of weather, continued weak
         economy and costs associated with the Cook Plant outage.

o        The reduced demand in the Ohio Companies attributable to the mild
         weather in the quarter and the economic pressures on industrial
         customers reduced pre-tax earnings by $15 million. Year-to-date pre-tax
         earnings increased $5 million due to the average fuel costs being less
         than the set recovery rate in revenues.

o        The reduction in pre-tax earnings of $38 million for the quarter and
         $83 million year-to-date of Texas supply is due to lower margins
         attributable to an outage at the STP nuclear plant and a separate
         provision for potential disallowance by the PUCT of certain historical
         fuel expenses. The Texas supply represents the gross margin for output
         of generating units in the ERCOT region and from "reliability must run"
         (RMR) contracts with ERCOT.

o        Federal Income Taxes decreased $21 million in the quarter and
         increased $19 million  year-to-date  due to the  fluctuation in
         pre-tax  income and the changes in the effective tax rate.

Investments - Gas Operations

Net Loss for the Gas Operations, which include Louisiana Intrastate Gas and
Houston Pipe Line operations, of $24 million in the quarter and $61 million
year-to-date is due to lower margins resulting from our reduced risk profile
and the year-to-date adjustment for the cumulative effect of accounting
changes. These decreases were partially offset by reduced operating and
interest expenses. Year-to-date Net Loss of $61 million included $23 million
(net of tax) of Loss from Cumulative Effect of Accounting Changes in
the first quarter resulting from the implementation of EITF 02-3 (see Note 4).

We have selected advisors to assist with developing a plan of divestiture of its
Louisiana Intrastate Gas holdings. See "Significant Factors - Possible
Divestitures" for additional information.

Investments- UK Operations

Net Loss for the UK Operations, which include Fiddler's Ferry and Ferrybridge
plants (FFF), decreased in the quarter $15 million and increased year-to-date
$70 million due to the fluctuations in operating income along with the
year-to-date adjustment for the cumulative effect of accounting changes.
Year-to-date Net Loss of $59 million included $15 million (net of tax) of Loss
from Cumulative Effect of Accounting Changes in the first quarter resulting from
the implementation of EITF 02-3 (see Note 4) and a $7 million (net of tax) Loss
from Cumulative Effect of Accounting Changes in the first quarter from the
implementation of SFAS 143 (see Note 4). During the second quarter, our U.K.
operations' improved performance was driven primarily by the results of our coal
and freight procurement group and reduced interest expense, as the debt
associated with the plants was retired in early April. Year-to-date our U.K.
operations posted a loss of $37 million driven by a $40 million loss in the
first quarter, due to the continued deterioration in power markets during that
period, and higher operations and maintenance costs which included severance and
redundancy closure costs of the Nordic trading office. Significant liquidity
issues in the U.K. market and the uncertain environmental regulations are still
concerns, so we expect this market to remain a difficult one for the foreseeable
future.

Investments - Other

Net Loss for Other investments, which consists of investments in independent
power plants, coal mines, river transportation, and communications as well as
the discontinued operations of SEEBOARD, CitiPower, Eastex and Pushan, of $26
million in the current quarter 2003 and $15 million year-to-date reflects
discontinued operations losses of $7 million in the quarter and $16 million
year-to-date. The Loss Before Discontinued Operations and Cumulative Effect of
Accounting Changes decreased $7 million in the quarter and $56 million
year-to-date due to lower international development costs, reduced interest
expense and lower costs to wind down operations. The 2002 Net Loss for Other
investments of $122 million in the quarter and $479 million year-to-date
includes discontinued operations losses of $96 million in the quarter and $74
million year-to-date as well as a $350 million (net of tax) first quarter
cumulative effect adjustment for the implementation of SFAS 142 (see Note 4) .
SFAS 142 required 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 SEEBOARD and CitiPower operations.

We have selected advisors to assist with developing a plan of divestiture of
coal mines and certain independent power plants. See "Significant Factors -
Possible Divestitures" for additional information.

Financial Condition
-------------------

Credit Ratings

The rating agencies currently have AEP and our rated subsidiaries on stable
outlook. Current ratings for AEP are as follows:

                                      Moody's        S&P            Fitch
                                      -------        ---            -----

AEP Short-Term Debt                    P-3           A-2             F-2
AEP Senior Unsecured Debt              Baa3          BBB             BBB
Senior Notes issued by AEP
  Resources (with support
  Agreement from AEP)                  Baa3          BBB             BBB+


During the first quarter of 2003, Moody's Investors Service (Moody's), Standard
& Poors (S&P) and Fitch Rating Service completed their reviews of AEP and our
rated subsidiaries. The reviews resulted in downgrades of debt ratings. The
completion of these reviews was a culmination of ratings action started during
2002.

Liquidity

At June 30, 2003, our liquidity sources totaled $3.9 billion and we had an
available liquidity position of $3.3 billion as illustrated in the table below:

Credit Facilities

                                        (in millions)          Maturity
                                                               --------
      Commercial Paper Backup:
        Lines of Credit                     $  750               5/04
        Lines of Credit                      1,000               5/05
        Lines of Credit                        750               5/06
      Euro Revolving Credit
        Facilities                             345              10/03
                                            ------
         Total                               2,845

      Liquidity Reserves                       300*
      Other Temporary
          Investments                          722*
                                            ------
      Total Liquidity Sources                3,867

      Less: Commercial Paper
              Outstanding                      547
                                            ------

      Total Available Liquidity             $3,320
                                            ======

* These components comprise the Cash and Cash Equivalents balance on our
Consolidated Balance Sheet at June 30, 2003 less $154 million of operational
cash on hand. We maintain the $300 million cash liquidity reserve fund to
support our marketing operations in the U.S. and keep additional cash on hand as
market conditions change.

In April 2003, our 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.

Cash Flow
<TABLE>
<CAPTION>

                                                                                       Six Months Ended June 30,
                                                                                       2003                2002
                                                                                     ---------          ---------

                                                                                            (in millions)
    <S>                                                                              <C>               <C>
    Cash and cash equivalents at beginning of period                                 $1,213            $   224
                                                                                     ------            -------
    Net cash from (used for) continuing operations:
      Operating activities                                                              798            $    97
      Investing activities                                                             (596)              (784)
      Financing activities                                                             (239)             1,038
    Effect of exchange rate changes on cash and
     cash equivalents                                                                  -                   (14)
                                                                                     ------            -------
    Net increase (decrease) in cash and cash equivalents                                (37)               337
                                                                                     ------            -------
    Cash and cash equivalents at end of period                                       $1,176            $   561
                                                                                     ======            =======
</TABLE>

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 three revolving credit
agreements.

Operating Activities

Cash flows from operating activities during the first half of 2003 were $798
million. Beginning with Income Before Discontinued Operations and Cumulative
Effect of Accounting Changes of $438 million, we add depreciation and deferred
taxes of $702 million and deduct $108 million of non-cash ECOM, $48 million in
mark-to-market changes and $190 million for working capital changes. The
negative working capital changes includes $90 million paid to Williams companies
in settlement for power and gas transactions, and $46 million in increased fuel
inventories.

Investing Activities

Cash flows used for investing activities during the first half of 2003 were $596
million compared to $784 million during the first half of 2002. The major reason
for the year-over-year variance was a construction expenditures reduction of
$135 million and proceeds of $41 million from the sale of assets in 2003 (see
Note 11).

Total consolidated plant and property additions for the first half 2003 were
$649 million, including continued construction expenditures for emission control
technology at several coal-fired generating plants (see Note 8).

Financing Activities

Cash flows from financing activities in the first half of 2003 decreased by
$1,277 million when compared to the first half of 2002 ($(239) million compared
to $1,038 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 half of 2003, AEP was able to retire $4,393
million of debt ($2,675 million short-term and $1,718 million of long-term) and
increase available cash primarily through the issuance of long-term financing
($3,546 million), issuance of common stock ($1,177 million) and the generation
of cash from operating activities.

Financing Activity

Common Stock Offering

On February 27, 2003, we priced our offering of 50 million shares of common
stock at a public offering price of $20.95 per share. We 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

In May 2003, a third party exercised its option to call $250 million of 5.50%
putable callable notes, issued by us in May 2001, for purchase and remarketing.
On May 15, 2003, we issued $300 million of 5.25% senior notes due 2015, a
portion of which was an exchange for the $250 million putable callable notes due
in 2003.

In March 2003, we 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, short-term debt and for other corporate purposes.

Also, see Note 15 for further information on financing activities.

Significant Factors
-------------------

Possible Divestitures

We have a strong commitment to continually evaluate the need to reallocate
resources to areas that effectively match investments with our business
strategy, provide greater potential for financial returns, and to dispose of
investments that no longer meet these principles.

We are seeking to divest assets that consist of domestic and international
unregulated generation, gas pipelines, a coal business and a communications
business. In June 2003, we began actively seeking buyers for 4,497 megawatts of
unregulated generating capacity in Texas to establish a market price for
calculation of stranded cost (see Note 7). Also in the second quarter 2003, we
hired an advisor to evaluate our coal business which has resulted in receipt of
non-binding bids which are currently being evaluated. In the third quarter of
2003, management hired advisors to review business options regarding various
components of our Gas Operations investment. This review is expected to be
completed before year-end and will include an analysis of alternatives for
packaging the business for sale along with review of our investment in gas
operations for impairment of value, including related goodwill of approximately
$300 million. Management is unable to determine the extent of an impairment, if
any, until such evaluation is complete. Management continues to have periodic
discussions with various parties on business alternatives for certain of our
other non-core investments.

The ultimate timing for a disposition of one or more of these assets will depend
upon market conditions and the value of any buyer's proposal. 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, cash flows and
financial condition.

Corporate Separation

As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), we have filed with the FERC and SEC seeking approval to
separate our regulated and unregulated operations. With the changes in our
business strategy, in response to energy market and business conditions,
management continues to evaluate corporate separation plans, including
determining whether legal corporate separation is appropriate in jurisdictions
where it is not legally required.

RTO Formation

As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), 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 May 2002, we announced an agreement with PJM to pursue terms for
participation in its RTO for AEP East companies with final agreements to be
negotiated. In July 2002, FERC issued an order accepting our decision to
participate in PJM, subject to specified conditions. AEP and other parties
continued to work on the resolution of those conditions.

In December 2002, our 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. In July 2003, the
KPSC ruled in part that we had failed to prove the benefit of our PJM RTO
membership to Kentucky retail customers and denied our request for approval of
transfer of functional control to PJM. Management plans to seek a rehearing.
Proceedings in the other states 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 and then only with
Virginia SCC approval.

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

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. Our
SPP companies are also regulated by state public utility commissions. 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.

Industry Restructuring

As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), restructuring and customer choice are in place in four
of the eleven state retail jurisdictions in which our electric utility companies
operate. Restructuring legislation generally 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 7.

Nuclear Plant Outages

In April 2003, engineers at STP, during inspections conducted regularly as part
of refueling outages, found wall cracks in two bottom mounted instrument guide
tubes of STP Unit 1. These cracks have been repaired and the unit is expected to
return to service in late summer. Our share of the direct cost of repair was
approximately $6 million through June 30, 2003. STP officials are working
closely with the NRC to safely return the unit to service. We have commitments
to provide power to customers during the outage. Therefore, we will be subject
to fluctuations in the market prices of electricity and purchased replacement
energy could be a significant cost.

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

Litigation

Federal EPA Complaint and Notice of Violation

As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings",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 our 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
8 for further discussion.

NOx Reductions

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 requirements began in May 2003 for TCC and begin in May
2005 for SWEPCo.

We are 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 of which $976 million has been spent through June 30, 2003.
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 8 for further discussion.

Enron Bankruptcy

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 our 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. In this regard,
Enron sent to AEPES a demand for payment of approximately $138 million relating
to AEPES' termination of trading contracts. 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 8 for further discussion.

Bank of Montreal Claim

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

Arbitration of Williams Claim

In 2002, we filed a demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding results from Williams' repudiation
of its obligations to provide physical power deliveries to AEP and Williams'
failure to provide the monetary security required for natural gas deliveries.
AEP and Williams settled the dispute with AEP paying $90 million to Williams in
June 2003. The resolution of this matter had an immaterial impact on results of
operations as we had accrued the amount paid. See Note 8 for further discussion.

Arbitration of PG&E Energy Trading, LLC Claim

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

Energy Market Investigations

As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), 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. Management responded to
the inquires and provided the requested information and has continued to respond
to supplemental data request in 2003.

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

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

Shareholders' Litigation

In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against us, certain
executives, members of the Board of Directors and certain investment banking
firms. These cases are in the initial pleading stage. We intend to vigorously
defend against these actions. See Note 8 for further discussion.

California Lawsuit

In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. We intend to vigorously
defend against this action. See Note 8 for further discussion.

Snohomish Settlement

In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract and paid $59 million to us. As a result of the contract
termination, we reversed $69 million of unrealized mark-to-market gains
previously recorded, resulting in a $10 million pre-tax loss.

Other Litigation

We continue to be involved in certain other legal matters discussed in the 2002
Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003).

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.

New Accounting Pronouncements

See Note 2 for a discussion of significant accounting policies and new
accounting pronouncements.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

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

Policies and procedures have been established to identify, assess, and manage
market risk exposures in our day to day operations. Our 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.

Roll-Forward of Mark-to-Market Risk Management Contract Net Assets

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

<TABLE>
<CAPTION>
                                              Roll-Forward of MTM Risk Management Contract Net Assets
                                                        Six Months Ended June 30, 2003


                                                                Utility        Gas                UK
                                                               Operations   Operations        Operations      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)                                  (139)           63                   8              (68)
        Fair Value of New Contracts When  Entered
         Into During the Period (b)                                -              -                   -                -
        Net Option Premiums Paid/(Received) (c)                     1            53                  (7)              47
        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 (d)                                             57           (31)                (12)              14
        Changes in Fair Value of Risk Management Contracts
         Allocated to Regulated Jurisdictions (e)                  27             -                   -               27
                                                                 ----         -----                ----             ----

        Ending Balance June 30, 2003                             $287         $ (68)               $ 20             $239
                                                                 ====         =====                ====             ====
</TABLE>


   (a)"(Gain) Loss from Contracts Realized/Settled During the Period"
       includes realized gains from risk management contracts and related
       derivatives that settled during 2003 that were entered into prior to
       2003.
   (b) The "Fair Value of New Contracts When Entered Into During the
       Period" represents the fair value of long-term contracts entered
       into with customers during 2003. The fair value is calculated as of
       the execution of the contract. Most of the fair value comes from
       longer term fixed price contracts with customers that seek to limit
       their risk against fluctuating energy prices. The contract prices
       are valued against market curves associated with the delivery
       location.
   (c)"Net Option Premiums Paid/(Received)" reflects the net option
       premiums paid/(received) as they relate to unexercised and unexpired
       option contracts that were entered into in 2003.
   (d)"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.
   (e)"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.

<TABLE>
<CAPTION>
                                                         Detail on MTM Risk Management Contract
                                                                      Net Assets
                                                                  As of June 30, 2003

                                                                Utility       Gas             UK
                                                               Operations  Operations      Operations    Consolidated
                                                               ----------  ----------      ----------    ------------
                                                                                  (in millions)
        <S>                                                        <C>          <C>           <C>              <C>
        Current Assets                                             $ 365        $ 451         $ 166            $   982
        Non Current Assets                                           418          316            91                825
                                                                   -----        -----         -----            -------
        Total MTM Energy Assets                                    $ 783        $ 767         $ 257            $ 1,807
                                                                   -----        -----         -----            -------

        Current Liabilities                                        $(281)       $(532)        $(156)           $  (969)
        Non Current Liabilities                                     (215)        (303)          (81)              (599)
                                                                   -----        -----         -----            -------
        Total MTM Risk Management Contract Liabilities             $(496)       $(835)        $(237)           $(1,568)
                                                                   -----        -----         -----            -------

        Total MTM Risk Management Contract Net Assets              $ 287        $ (68)        $  20                239
                                                                   =====        =====         =====
        Net Non-Trading Related Derivative Contracts                                                              (114)

        Net Fair Value of Risk Management and  Derivative
        Contracts                                                                                              $   125
                                                                                                               =======
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>
                                                   Maturity and Source of Fair Value of MTM
                                                     Risk Management Contract Net Assets
                                                  Fair Value of Contracts as of June 30, 2003

                                               Remainder                                                          After
Utility Operations:                              2003             2004       2005        2006         2007         2007      Total
                                                 ----             ----       ----        ----         ----         ----      -----
                                                                                   (in millions)
<S>                                                 <C>          <C>        <C>         <C>          <C>          <C>         <C>
Prices Actively Quoted - Exchange Traded
 Contracts                                          $ (4)        $ (6)      $ (3)       $(2)         $ -          $ -         $(15)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                      46           59         23         19            6            -          153
Prices Based on Models and Other
 Valuation Methods (b)                                19           16         14         23           24           53          149
                                                   -----         ----       ----        ---          ---          ---         ----

    Total                                          $  61         $ 69       $ 34        $40          $30          $53         $287
                                                   =====          ===       ====        ===          ===          ===         ====

Gas Operations:
Prices Actively Quoted - Exchange
 Traded Contracts (a)                              $(119)        $ 90       $  9        $ -          $ -          $ -         $(20)
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                             119           16         -           -            -            -          135
Prices Based on Models and Other
 Valuation Methods (b)                              (144)         (32)       (12)         5            8           (8)        (183)
                                                   -----         ----       ----        ---          ---          ---        -----

    Total                                          $(144)        $ 74       $ (3)       $ 5          $ 8          $(8)       $ (68)
                                                   =====         ====       ====        ===          ===          ===        =====

UK Operations:
Prices Actively Quoted - Exchange Traded
 Contracts (a)                                     $ -           $ -        $ -         $ -          $ -          $ -         $ -
Prices Provided by Other External Sources
- OTC Broker Quotes (a)                               14            6          8         (3)           -            -           25
Prices Based on Models and Other
 Valuation Methods (b)                                (2)          -          (5)         -            2            -           (5)
                                                   -----         ----       ----        ---          ---          ---         ----

    Total                                          $  12         $  6       $  3        $(3)         $ 2          $ -         $ 20
                                                   =====         ====       ====        ===          ===          ===         ====

Consolidated:
Prices Actively Quoted - Exchange Traded
 Contracts                                         $(123)        $ 84       $  6        $(2)         $ -          $ -         $(35)
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                             179           81         31         16            6            -          313
Prices  Based on Models and Other
 Valuation Methods (b)                              (127)         (16)        (3)        28           34           45          (39)
                                                   -----         ----       ----        ---          ---          ---         ----

    Total                                          $ (71)        $149       $ 34        $42          $40          $45         $239
                                                   =====         ====       ====        ===          ===          ===         ====
</TABLE>

(a) Prices provided by other external sources - Reflects information obtained
  from over-the-counter brokers, industry services, or multiple-party on-line
  platforms.
(b) Modeled - In the absence of pricing information from external sources,
  modeled information is derived using valuation models developed by the
  reporting entity, reflecting when appropriate, option pricing theory,
  discounted cash flow concepts, valuation adjustments, etc. and may require
  projection of prices for underlying commodities beyond the period that prices
  are available from third-party sources. In addition, where external pricing
  information or market liquidity are limited, such valuations are
  classified as modeled.


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

<TABLE>
<CAPTION>

                              Maximum Tenor of the Liquid Portion of Risk Management Contracts
                                                    As of June 30, 2003
        Domestic                                                                                                Tenor
        --------                                                                                             (in months)
        <S>                 <C>                                  <C>                                              <C>
        Natural Gas         Forward Purchases and Sales
                                                                 NYMEX Henry Hub Gas                              66
                                                                 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)        Forward Purchases and Sales
                                                                 Power East - Cinergy                             42
                                                                 Power East - PJM                                 42
                                                                 Power East - NYPP                                30
                                                                 Power East - NEPOOL                              18
                                                                 Power East - ERCOT                               18
                                                                 Power East - TVA                                  0
                                                                 Power East - Com Ed                              18
                                                                 Power East - Entergy                             18
                                                                 Power West - PV, NP15,SP15,MidC,Mead             54
                            Peak Power Volatility
                             (Options)                           Cinergy                                          18
                            OffPeak Power Volatility             All Regions                                       0

        Natural Gas
         Liquids                                                                                                  11

        WTI Crude                                                                                                 48

        Emissions                                                                                                 30

        Coal                                                                                                      30

        International

        Power                                                    United Kingdom                                   36

        Coal                Forward Purchases and Sales          United Kingdom                                   15

                            Financial Transactions (Swaps)       Europe                                           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.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges AEP has in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in Accumulated Other Comprehensive Income (AOCI), the
table does not provide an all-encompassing picture of AEP's hedging activity).
The table further indicates what portions of these hedges are expected to be
reclassified 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).

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.

      Cash Flow Hedges included in Accumulated Other Comprehensive Income
                    On the Balance Sheet as of June 30, 2003


                                Accumulated Other           Portion Expected
                                  Comprehensive             to Be Reclassified
                                     Income                 to Earnings During
                                (Loss) After Tax(a)         Next 12 Months (b)
                                ------------------          ------------------
                                                 (in millions)
        Power                       $ (92)                       $(44)
        Foreign Currency              (10)                         (8)
        Interest Rate                 (14)                         (5)
                                    -----                        ----

        Consolidated                $(116)                       $(57)
                                    =====                        ====

<TABLE>
<CAPTION>

                                                 Total Other Comprehensive Income Activity
                                                        Six Months Ended June 30, 2003

                                                                            Foreign                          AEP
                                                            Power           Currency    Interest Rate    Consolidated
                                                            -----           --------    -------------    ------------
                                                                                 (in millions)
        <S>                                                 <C>               <C>           <C>              <C>
        Accumulated OCI, December 31, 2002                  $ (3)             $(1)          $(12)            $ (16)
        ----------------------------------
        Changes in Fair Value (c)                            (89)              (9)            (3)             (101)
        Reclassifications from OCI to Net
         Income (d)                                           -               -                1                 1
                                                            ----             ----            ----            -----
        Accumulated OCI Derivative Loss June 30, 2003       $(92)            $(10)          $(14)            $(116)
                                                            ====             ====           ====             =====
</TABLE>

(a)       Accumulated other comprehensive income (loss) after tax - Gains/losses
          are net of related income taxes that have not yet been included in the
          determination of net income; reported as a separate component of
          shareholders' equity on the balance sheet.
(b)       Portion expected to be reclassified to earnings during the next 12
          months - Amount of gains or losses (realized or unrealized) from
          derivatives used as hedging instruments that have been deferred and
          are expected to be reclassified into net income during the next 12
          months at the time the hedged transaction affects net income.
(c)       Changes in fair value - Changes in the fair value of derivatives
          designated as 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.

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 June 30, 2003. At June 30, 2003 AEP's credit exposure net of credit
collateral to sub investment grade counterparties was approximately 10%,
expressed in terms of net MTM assets and net receivables. 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
June 30, 2003 the following table approximates counterparty credit quality and
exposure for AEP based on netting across AEP entities, commodities and
instruments:

<TABLE>
<CAPTION>

                                                                                                Number of           Net Exposure of
     Counterparty                          Exposure Before          Credit         Net        Counterparties        Counterparties
     Credit Quality:                       Credit Collateral      Collateral    Exposure          > 10%                  > 10%
     --------------                        -----------------      ----------    --------          -----                  -----
                                                                           (in millions)
     <S>                                         <C>                <C>           <C>                 <C>                <C>
     Investment Grade                            $1,112             $143          $  969              1                  $131
     Split Rating                                    37               -               37              1                    36
     Non-Investment Grade                           191              122              69              3                    33
     No External Ratings:
       Internal Investment
         Grade                                      322                3             319              2                   126
       Internal Non-Investment
         Grade                                      143               58              85              1                    13
                                                 ------             ----          ------                                 ----
     Total                                       $1,805             $326          $1,479                                 $339
                                                 ======             ====          ======                                 ====
</TABLE>

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

Generation Plant Hedging Information

This table provides information on operating measures regarding 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.

                      Generation Plant Hedging Information
                           Estimated Next Three Years
                               As of June 30, 2003

                                                2003       2004        2005
                                                ----       ----        ----
Estimated Plant Output Hedged (a)                94%        90%         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
June 30, 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 year-to-date:

                                  VaR Model
                                  ---------

                   June 30,                      December 31,
                    2003                            2002
                (in millions)                   (in millions)
           End  High Average Low             End High Average Low
           ---  ---- ------- ---             --- ---- ------- ---

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

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

The AEP VaR model results are adjusted using standard statistical treatments to
calculate the CCRO VaR reporting metrics listed below. The adjustments are made
to take the AEP model results from a one-day 95% confidence level to a ten-day
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>
                                                                               CCRO VaR Metrics

                                                                      Average for
                                                     End of          Year-to-Date         High for                Low for
                                                 June 30,  2003           2003        Year-to-Date  2003      Year-to-Date 2003
                                                 --------------       -----------     ------------------      -----------------
                                                                             (in millions)
        <S>                                           <C>               <C>                  <C>                    <C>
        95% Confidence Level, Ten-Day
          Holding Period, Two-Tailed                  $20               $27                  $71                    $17

        99% Confidence Level, One-Day
          Holding Period, Two-Tailed                  $ 8               $11                  $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 $1,217
million at June 30, 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.

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) and in the ERCOT area of
Texas (effective January 1, 2002) 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, principally coal
and freight. As a result, AEP is subject to price risk. The amount of risk
taken 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>
<TABLE>
<CAPTION>
                                    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                 CONSOLIDATED STATEMENTS OF OPERATIONS
                                                (in millions, except per-share amounts)
                                                           (UNAUDITED)
                                                                             Three Months Ended             Six Months Ended
                                                                                  June 30,                       June 30,
                                                                              2003             2002          2003            2002
                                                                              ----             ----          ----            ----

REVENUES:
<S>                                                                          <C>              <C>           <C>             <C>
   Utility Operations                                                        $2,628           $2,660        $5,401          $4,918
   Gas Operations                                                               829              670         1,931           1,103
   U.K. Operations and Other                                                    212              251           417             552
                                                                             ------           ------        ------          ------
          TOTAL REVENUES                                                      3,669            3,581         7,749           6,573
                                                                             ------           ------        ------          ------
EXPENSES:
  Fuel for Electric Generation                                                  850              631         1,510           1,252
  Purchased Electricity for Resale                                              215               78           420             107
  Purchased Gas for Resale                                                      708              712         1,857           1,066
  Maintenance and Other Operation                                               981            1,199         1,944           2,205
  Depreciation and Amortization                                                 336              351           651             683
  Taxes Other Than Income Taxes                                                 157              183           345             374
                                                                             ------           ------        ------          ------
           TOTAL EXPENSES                                                     3,247            3,154         6,727           5,687
                                                                             ------           ------        ------          ------

OPERATING INCOME                                                                422              427         1,022             886

OTHER INCOME                                                                     86               49           204              61

OTHER EXPENSE                                                                    57                6           102              26

LESS:INTEREST                                                                   198              196           403             391

      PREFERRED STOCK DIVIDEND REQUIREMENTS
       OF SUBSIDIARIES                                                            3                3             6               5

      MINORITY INTEREST IN FINANCE SUBSIDIARY                                     8                9            17              18
                                                                             ------           ------        ------          ------

INCOME BEFORE INCOME TAXES                                                      242              262           698             507
INCOME TAXES                                                                     60              104           260             190
                                                                             ------           ------        ------          ------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT                     182              158           438             317
  Discontinued Operations (net of tax)                                           (7)             (96)          (16)            (74)
  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)                                                            $  175           $   62        $  615          $ (107)
                                                                             ======           ======        ======          ======
AVERAGE NUMBER OF SHARES OUTSTANDING                                            395              326           376             324
                                                                                ===              ===           ===             ===
EARNINGS (LOSS) PER SHARE:
   Income Before Discontinued Operations And
    Cumulative Effect of Accounting Changes                                  $ 0.46           $ 0.48        $ 1.17          $ 0.98
   Discontinued Operations                                                    (0.02)           (0.29)        (0.04)          (0.23)
   Cumulative Effect of Accounting Changes                                      -                -            0.51           (1.08)
                                                                             ------           ------        ------          ------
   EARNINGS (LOSS) PER SHARE (BASIC
    AND DILUTIVE)                                                            $ 0.44           $ 0.19        $ 1.64          $(0.33)
                                                                             ======           ======        ======          ======

CASH DIVIDENDS PAID PER SHARE                                                $ 0.35           $ 0.60        $ 0.95          $ 1.20
                                                                             ======           ======        ======          ======
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
                                      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                     CONSOLIDATED BALANCE SHEETS
                                                            (UNAUDITED)

                                                                                     June 30, 2003            December 31, 2002
                                                                                     -------------            -----------------
                                                                                                  (in millions)
ASSETS

CURRENT ASSETS:
<S>                                                                                     <C>                          <C>
    Cash and Cash Equivalents                                                           $ 1,176                      $ 1,213
    Accounts Receivable (net)                                                             1,685                        1,740
    Fuel, Materials and Supplies                                                          1,178                        1,166
    Risk Management Assets                                                                1,010                        1,012
    Other                                                                                   883                          935
                                                                                        -------                      -------

       TOTAL CURRENT ASSETS                                                               5,932                        6,066
                                                                                        -------                      -------

PROPERTY, PLANT AND EQUIPMENT:
   Electric:
     Production                                                                          17,575                       17,031
     Transmission                                                                         5,962                        5,882
     Distribution                                                                         9,709                        9,573
   Other (including gas, coal mining and
     nuclear fuel)                                                                        3,926                        3,965
   Construction Work in Progress                                                          1,272                        1,406
                                                                                        -------                      -------
       Total Property, Plant and Equipment                                               38,444                       37,857
   Accumulated Depreciation and Amortization                                             16,031                       16,173
                                                                                        -------                      -------

       NET PROPERTY, PLANT AND EQUIPMENT                                                 22,413                       21,684
                                                                                        -------                      -------

REGULATORY ASSETS                                                                         2,669                        2,688
                                                                                        -------                      -------

SECURITIZED TRANSITION ASSETS                                                               716                          735
                                                                                        -------                      -------

INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS                                              283                          283
                                                                                        -------                      -------

GOODWILL                                                                                    396                          396
                                                                                        -------                      -------

ASSETS HELD FOR SALE                                                                        219                          292
                                                                                        -------                      -------

LONG-TERM RISK MANAGEMENT ASSETS                                                            836                          819
                                                                                        -------                      -------

OTHER ASSETS                                                                              1,895                        1,783
                                                                                        -------                      -------

          TOTAL ASSETS                                                                  $35,359                      $34,746
                                                                                        =======                      =======
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
                                       AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                      CONSOLIDATED BALANCE SHEETS
                                                               (UNAUDITED)

                                                                                        June 30, 2003            December 31, 2002
                                                                                        -------------            -----------------
                                                                                                    (in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
<S>                                                                                        <C>                      <C>
  Accounts Payable                                                                         $ 1,860                  $ 2,030
  Short-term Debt                                                                              567                    3,164
  Long-term Debt Due Within One Year                                                         1,020                    1,633
  Risk Management Liabilities                                                                1,055                    1,113
  Other                                                                                      1,739                    1,802
                                                                                           -------                  -------

       TOTAL CURRENT LIABILITIES                                                             6,241                    9,742
                                                                                           -------                  -------

LONG-TERM DEBT                                                                              10,934                    8,487
                                                                                           -------                  -------

EQUITY UNIT SENIOR NOTES                                                                       376                      376
                                                                                           -------                  -------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                          666                      481
                                                                                           -------                  -------

DEFERRED INCOME TAXES                                                                        4,068                    3,916
                                                                                           -------                  -------

DEFERRED INVESTMENT TAX CREDITS                                                                440                      455
                                                                                           -------                  -------

DEFERRED CREDITS AND REGULATORY LIABILITIES                                                    866                      770
                                                                                           -------                  -------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2                                                                        180                      185
                                                                                           -------                  -------

LIABILITIES HELD FOR SALE                                                                      103                      142
                                                                                           -------                  -------

OTHER NONCURRENT LIABILITIES                                                                 2,074                    1,903
                                                                                           -------                  -------

COMMITMENTS AND CONTINGENCIES (Note 8)

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                                                        533                      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. . . . . 404,001,845   347,835,212
      (8,999,992 shares were held in treasury at  June 30, 2003
               and December 31, 2002)                                                        2,626                    2,261
  Paid-in Capital                                                                            4,182                    3,413
  Accumulated Other Comprehensive Income (Loss)                                               (670)                    (609)
  Retained Earnings                                                                          2,275                    1,999
                                                                                           -------                  -------
          TOTAL COMMON SHAREHOLDERS' EQUITY                                                  8,413                    7,064
                                                                                           -------                  -------

              TOTAL LIABILITIES AND SHAREHOLDERS'  EQUITY                                  $35,359                  $34,746
                                                                                           =======                  =======
</TABLE>

See Notes to Consolidated Financial Statements.


<PAGE>
<TABLE>
<CAPTION>
                                    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                             (UNAUDITED)

                                                                                                      Six Months Ended  June 30,
                                                                                                        2003              2002
                                                                                                        ----              ----
                                                                                                            (in millions)
OPERATING ACTIVITIES:

<S>                                                                                                     <C>             <C>
   Net Income (Loss)                                                                                    $  615          $(107)
   Plus:  Discontinued Operations                                                                           16             74
                                                                                                        -------         ------
   Income from Continuing Operations                                                                       631            (33)
   Adjustments for Noncash Items:
      Depreciation and Amortization                                                                        651            687
      Deferred Income Taxes                                                                                 51           (106)
      Deferred Investment Tax Credits                                                                      (16)           (10)
      Cumulative Effect of Accounting Changes                                                             (193)           350
      Amortization of Deferred Property Taxes                                                             -                35
      Amortization of Cook Plant Restart Costs                                                              20             20
      Mark to Market of Risk Management Contracts                                                          (48)           207
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable, net                                                                              46           (919)
      Fuel, Materials and Supplies                                                                         (46)           250
      Accrued Utility Revenues                                                                              51           (176)
      Prepayments and Other                                                                                 93           (411)
      Accounts Payable                                                                                    (177)           343
      Taxes Accrued                                                                                         36            (14)
      Interest Accrued                                                                                      11             39
   Over/Under Fuel Recovery                                                                                 85            (35)
   Change in Other Assets                                                                                 (209)          (325)
   Change in Other Liabilities                                                                            (188)           195
                                                                                                        ------          -----
          Net Cash Flows From  Operating Activities                                                        798             97
                                                                                                        ------          -----

INVESTING ACTIVITIES:
  Construction Expenditures                                                                               (649)          (784)
  Proceeds from Sale of Assets                                                                              41             -
  Other                                                                                                     12             -
                                                                                                        ------          -----
          Net Cash Flows Used For Investing Activities                                                    (596)          (784)
                                                                                                        ------          -----

FINANCING ACTIVITIES:
  Issuance of Common Stock                                                                               1,177            656
  Issuance of Long-term Debt                                                                             3,546          1,786
  Issuance of Equity Unit Senior Notes                                                                    -               334
  Change in Short-term Debt, net                                                                        (2,675)          (980)
  Retirement of Long-term Debt                                                                          (1,718)          (371)
  Retirement of Preferred Stock                                                                             (2)          -
  Retirement of Minority Interest                                                                         (225)          -
  Dividends Paid on Common Stock                                                                          (342)          (387)
                                                                                                        ------          -----
          Net Cash Flows From (Used For) Financing Activities                                             (239)         1,038
                                                                                                        ------          -----
Effect of Exchange Rate Change on Cash                                                                    -               (14)
                                                                                                        ------          -----
Net Increase (Decrease) in Cash and Cash Equivalents                                                       (37)           337
Cash and Cash Equivalents at Beginning of Period                                                         1,213            224
                                                                                                        ------          -----
Cash and Cash Equivalents at End of Period                                                              $1,176          $ 561
                                                                                                        ======          =====
Net Increase in Cash and Cash Equivalents from  Discontinued  Operations                                $   11          $  19
Cash and Cash Equivalents from Discontinued Operations -  Beginning of Period                                8            108
                                                                                                        ------          -----
Cash and Cash Equivalents from Discontinued Operations - End  of Period                                 $   19          $ 127
                                                                                                        ======          =====
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $364 million and $335
million and for income taxes was $155 million and $307 million in 2003 and 2002,
respectively. Noncash acquisitions under capital leases were $1 million in 2003
and $2 million in 2002.

See Notes to Consolidated Financial Statements.
<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                                      108          568                                                676
Common Stock Dividends                                                                   (387)                               (387)
Other                                                                      (61)                                               (61)
                                                                                                                           ------
                                                                                                                            8,457
                                                                                                                           ------
Comprehensive Income (Loss):
  Other Comprehensive Income (Loss), Net of
    Taxes:
     Foreign Currency Translation Adjustments                                                                  73              73
     Unrealized Losses on Cash Flow Hedges                                                                    (39)            (39)
  Net Loss                                                                               (107)                               (107)
                                                                                                                           ------
      Total Comprehensive Income (Loss)                                                                                       (73)
                                                            ------      ------         ------              ------          ------

JUNE 30, 2002                                              $2,261       $3,413         $2,802              $ (92)          $8,384
                                                           ======       ======         ======              ======          ======



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

Issuance of Common Stock                                      365          812                                              1,177
Common Stock Dividends                                                                   (342)                               (342)
Common Stock Expense                                                       (35)                                               (35)
Other                                                                       (8)             3                                  (5)
                                                                                                                           ------
                                                                                                                            7,859
                                                                                                                           ------
Comprehensive Income:
  Other Comprehensive Income (Loss), Net of
     Taxes:
      Foreign Currency Translation Adjustments                                                                23               23
      Unrealized Gains on Securities                                                                           1                1
      Unrealized Losses on Cash Flow Hedges                                                                 (100)            (100)
      Minimum Pension Liability                                                                               15               15
  Net Income                                                                              615                                 615
                                                                                                                           ------
      Total Comprehensive Income                                                                                              554
                                                           ------       ------         ------              -----           ------

JUNE 30, 2003                                              $2,626       $4,182         $2,275              $(670)          $8,413
                                                           ======       ======         ======              =====           ======
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>


             AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                  JUNE 30, 2003
                                  -------------
                                   (UNAUDITED)

1.      GENERAL
        -------

        The accompanying unaudited interim financial statements should be read
        in conjunction with the 2002 Annual Report (as updated by the Current
        Report on Form 8-K dated May 14, 2003) as incorporated in and filed with
        the Form 10-K/A.

        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
        on 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 from transactions associated with our UK
        operations (see Note 30 in the Current Report on Form 8-K dated May
        14, 2003). As a result, Gas Operations revenues decreased by $2 million
        and $49 million, UK Operations and Other revenues decreased by $3
        million and $13 million, Fuel for Electric Generation decreased by $17
        million and $44 million, and Purchased Gas for Resale decreased by $104
        million and $162 million for the three and six month periods ended June
        30, 2002, respectively. Expenses for Maintenance and Other Operation
        increased by $109 million and $130 million and Taxes Other Than Income
        Taxes increased by $7 million and $14 million for the three and six
        month periods ended June 30, 2002, respectively. 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
        -----------------------------------------------------------------

        Accumulated Other Comprehensive Income

        Approximately $57 million of net losses from cash flow hedges in
        Accumulated Other Comprehensive Income (Loss) at June 30, 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 approximately
        seven years.

        SFAS 143 "Accounting for Asset Retirement Obligations"

        We implemented SFAS 143, "Accounting for Asset Retirement Obligations",
        effective January 1, 2003 which requires entities to record a liability
        at fair value for any legal obligations for asset retirements in the
        period incurred. Upon establishment of a legal liability, SFAS 143
        requires a corresponding asset to be established which will be
        depreciated over its useful life. SFAS 143 requires that a cumulative
        effect of change in accounting principle be recognized for the
        cumulative accretion and accumulated depreciation that would have been
        recognized had SFAS 143 been applied to existing legal obligations for
        asset retirements. In addition, the cumulative effect of change in
        accounting principle is favorably affected by the reversal of
        accumulated removal cost 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.

        We completed a review of our asset retirement obligations and concluded
        that at present, we have related legal liabilities for nuclear
        decommissioning costs for our Cook Plant and our partial ownership in
        the South Texas Project, as well as liabilities for the retirement of
        certain ash ponds, wind farms, the U.K. Plants, and certain coal mining
        facilities. Since we presently recover our nuclear decommissioning costs
        in our regulated cash flow and thus had existing balances recorded for
        such nuclear retirement obligations, we 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 our regulated operations. In
        the first quarter of 2003, we recorded an unfavorable cumulative effect
        of $45.4 million after tax for our non-regulated operations ($38.0
        million related to Ash Ponds in the Utility Operations segment, $7.2
        million related to U.K. Plants in the Investments - UK Operations
        segment and $0.2 million for Wind Mills in the Investments - Other
        segment).

        Certain of our operating companies have recorded in Accumulated
        Depreciation and Amortization, removal costs collected from ratepayers
        for certain assets that do not have associated legal asset retirement
        obligations. To the extent that such operating companies have now been
        deregulated, in the first quarter 2003, we reversed the balance of such
        removal costs, totaling $287.2 million after tax, from accumulated
        depreciation which resulted in a net favorable cumulative effect in the
        first quarter of 2003. However, we did not adjust the balance of such
        removal costs for our regulated operations, and in accordance with the
        present method of recovery, will continue to record such amounts through
        depreciation expense and accumulated depreciation. We estimate that we
        have approximately $1.2 billion of such regulatory liabilities recorded
        in Accumulated Depreciation and Amortization as of both June 30, 2003
        and December 31, 2002.

        The net favorable cumulative effect of the change in accounting
        principle for the six months ended June 30, 2003 consists of the
        following:

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

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

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

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

<TABLE>
<CAPTION>

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

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

        Accretion expense                               25.8                   2.7                     1.0                29.5

        Liabilities incurred                             -                      -                      0.2                 0.2

        Foreign currency
          Translation                                    -                      -                      3.2                 3.2
                                                      ------                 -----                   -----              ------

        Asset Retirement Obligation
        Liability at June 30, 2003                    $744.1                 $72.5                   $41.6              $858.2
                                                      ======                 =====                   =====              ======
</TABLE>

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

        As of June 30, 2003 and December 31, 2002, the fair value of assets that
        are legally restricted for purposes of settling the nuclear
        decommissioning liabilities totaled $778 million and $716 million,
        respectively, recorded in Other Assets on our Consolidated Balance
        Sheets.

        Pro forma net income and earnings per share have not been presented for
        the quarter ended June 30, 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.

        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. See New Accounting Pronouncements in
        Note 1 of the 2002 Annual Report (as updated by the Current Report on
        Form 8-K dated May 14, 2003) for further information.

        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 certain decisions made by the FASB as
        part of the Derivative Implementation Group process and to incorporate
        clarifications of the definition of a derivative and which contracts
        qualify as "normal purchase/normal sale." SFAS 149 also amends certain
        other existing pronouncements. Except for certain provisions of SFAS 149
        discussed below, SFAS 149 is effective for contracts entered into or
        modified after June 30, 2003, and for hedging relationships designated
        after June 30, 2003. The provisions of SFAS 149 relating to decisions
        cleared by the FASB as part of the Derivative Implementation Group
        process shall continue to be applied in accordance with their respective
        effective dates. In addition, certain paragraphs of SFAS 149, which
        relate to forward purchases and sales of when-issued securities or other
        securities that do not yet exist, shall be applied to both existing
        contracts and new contracts entered into after June 30, 2003. We are
        currently assessing the impact of the adoption of SFAS 149.

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

        SFAS 150 was effective for us on July 1, 2003. SFAS 150 is the result of
        the first phase of the FASB's project to eliminate from the balance
        sheet the "mezzanine" presentation of items with characteristics of both
        liabilities and equity, so that no such items will be presented between
        liabilities and equity.

        SFAS 150 requires that the following three types of freestanding
        financial instruments be reported as liabilities: (1) mandatorily
        redeemable shares, (2) instruments other than shares that could require
        the issuer to buy back some of its shares in exchange for cash or other
        assets and (3) obligations that can be settled with shares, the monetary
        value of which is either (a) fixed, (b) tied to the value of a variable
        other than the issuer's shares, or (c) varies inversely with the value
        of the issuer's shares. Measurement of these liabilities generally is to
        be at fair value, with the payment or accrual of "dividends" and other
        amounts to holders reported as interest cost. Upon adoption of the new
        statement, any measurement change for these liabilities is to be
        reported as the cumulative effect of a change in accounting principle.
        We are currently assessing the impact of the adoption of SFAS 150.

        Beginning with our third quarter 2003 financial statements, $321 million
        of certain subsidiary obligated, mandatorily redeemable, preferred
        securities of subsidiary trusts holding solely junior subordinated
        debentures of such subsidiaries, $83 million of mandatorily redeemable
        cumulative preferred stock of subsidiaries, and $376 million of equity
        unit senior notes, all of which are currently given mezzanine
        presentation, are expected to be reclassified as liabilities on our
        balance sheet. We are, however, still assessing the ultimate impact of
        SFAS 150.

        Future Accounting Changes

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

3.      STOCK-BASED COMPENSATION PLANS
        ------------------------------

        We have two stock-based employee compensation plans with outstanding
        stock options. We account 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 our earnings, as all
        options granted under these plans had exercise prices equal to or above
        the market value of the underlying common stock on the date of grant.

        We awarded restricted stock units to certain employees in March 2003
        which 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 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 and second quarters of
        2003 in AEP's Consolidated Statements of Operations was not significant.

        The following table illustrates the effect on our Net Income (Loss) and
        earnings (loss) per share as if we had historically 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                Six Months Ended
                                                                                    June 30,                         June 30,
                                                                             2003                2002          2003          2002
                                                                             ----                ----          ----          ----
                                                                                       (in millions, except per share data)

          <S>                                                               <C>                <C>            <C>          <C>
          Net Income (Loss), as reported                                    $ 175              $   62         $ 615        $ (107)
          Add: Stock-based compensation expense included in
            reported net income, net of related tax effects                    -  (a)             -             -  (a)        -
          Deduct: Stock-based employee compensation expense
            determined under fair value based method for all awards,
            net of related tax effects                                         (2)                 (3)           (3)          (5)
                                                                            -----              ------         -----        ------
          Pro Forma Net Income (Loss)                                       $ 173              $   59         $ 612        $ (112)
                                                                            =====              ======         =====        ======

          Earnings (Loss) per Share:
              Basic - as Reported                                           $0.44              $ 0.19         $1.64        $(0.33)
              Basic - Pro Forma                                              0.44                0.18          1.63         (0.35)
              Diluted - as Reported                                          0.44                0.19          1.64         (0.33)
              Diluted - Pro Forma                                            0.44                0.18          1.63         (0.35)
</TABLE>

        (a) Compensation expense related to restricted units during the second
            quarter of 2003 was not significant.

4.      CUMULATIVE EFFECT OF ACCOUNTING CHANGES
        ---------------------------------------

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

        SFAS 143, "Accounting for Asset Retirement Obligations" (see Note 2),
        was effective on January 1, 2003. In the first quarter of 2003, we
        recorded $242 million in after-tax income related to the recording of
        Asset Retirement Obligations in our 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 eliminated 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. We have recorded a $49 million after tax charge
        against net income as Accounting for Risk Management Contracts in our
        Consolidated Statements of Operations in Cumulative Effect of Accounting
        Changes in the first quarter of 2003 ($11 million in Utility Operations,
        $23 million in Investments - Gas Operations and $15 million in
        Investments - UK Operations segments). This amount will be realized when
        the positions settle.

5.      GOODWILL AND OTHER INTANGIBLE ASSETS
        ------------------------------------

        Goodwill

        There were no significant changes in the carrying amount of goodwill for
        the six months ended June 30, 2003.

        Acquired Intangible Assets

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

                                                                   June 30, 2003                          December 31, 2002
                                                           -----------------------------           ------------------------------

                                                             Gross                                  Gross
                                          Amortization      Carrying          Accumulated          Carrying          Accumulated
                                            Life             Amount          Amortization           Amount           Amortization
                                          ------------      --------         ------------          --------          ------------
                                                                             (in millions)

       <S>                                     <C>           <C>                <C>                 <C>                 <C>
       Software and customer list               2            $  -               $ -                 $ 0.5               $0.2
       Software acquired                        3              0.5               0.2                  0.5                 -
       Patent                                   5              0.1                -                   0.1                 -
       Easements                               10              2.2               0.2                   -                  -
       Trade name and
        administration of contracts             7              2.4               0.7                  2.4                0.6
       Purchased technology                    10             10.3               1.5                 10.3                1.0
       Advanced royalties                      10             29.4               6.2                 29.4                4.7
                                                             -----              ----                -----               ----

         Total                                               $44.9              $8.8                $43.2               $6.5
                                                             =====              ====                =====               ====
</TABLE>

       The software and customer list intangible asset was sold as part of the
       transfer of the Nordic Trading Business during the second quarter 2003.

       Intangible asset amortization expense was $1.4 million and $1.0 million
       for the three months ended June 30, 2003 and June 30, 2002. Intangible
       asset amortization expense was $2.6 million and $2.0 million for the six
       months ended June 30, 2003 and June 30, 2002.

       Estimated aggregate amortization expense is $4.7 million in 2004, $4.6
       million in 2005 through 2007, $4.4 million in 2008 and $4.2 million in
       2009.

       Intangible assets subject to amortization are recorded in Other Assets in
       the Consolidated Balance Sheets.

  6.   RATE MATTERS
       ------------

       Fuel in SPP

       As discussed in Note 6 of the 2002 Annual Report (as updated by the
       Current Report on Form 8-K dated May 14, 2003), in 2001, the PUCT delayed
       the start of customer choice in the SPP area of Texas. In May 2003, the
       PUCT ordered that competition would not begin in the SPP areas before
       January 1, 2007. 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, for reconciling 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

       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 the SPP area.
       The under-recovery balance at December 31, 2001 for TNC's service within
       SPP was $0.7 million including interest. As noted above, TNC's SPP
       customers are now being served by SWEPCo's REP.

       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.
       On May 28, 2003, the PUCT remanded TNC's final fuel reconciliation to the
       ALJ to consider several issues. Two of these remand issues could result
       in additional disallowances. The issues are the sharing of off-system
       sales margins from AEP's trading activities with customers through the
       fuel factor for five years per the PUCT's interpretation of the Texas
       AEP/CSW merger settlement and the inclusion of January 2002 fuel factor
       revenues and associated costs in the determination of the under-recovery.
       TNC made a filing on July 15, 2003 addressing the remand issues. The PUCT
       is proposing that the sharing of off-system sales margins should continue
       beyond the termination of the fuel factor. This would result in the
       sharing of margins for an additional three and one half years after the
       end of the Texas ERCOT fuel factor. Management believes that the Texas
       merger settlement only provided for sharing of margins during the period
       fuel and generation costs were regulated by the PUCT and that after a
       more thorough review of the evidence it is only reasonably possible that
       the PUCT will determine after the remand proceeding that TNC should share
       margins after the end of the Texas fuel factor. Due to a provision
       established in the first quarter, the resolution of the fuel factor issue
       should have an immaterial impact on results of operations. However, the
       decision of the PUCT could result in additional income reductions for
       these issues. It is presently expected that the ALJ's PFD and the PUCT's
       final decision of these remanded issues will occur in late 2003 or early
       2004.

       In February 2002, TNC received a final order from the PUCT in a fuel
       reconciliation covering the period July 1997 - June 2000 and reflected
       the order in its financial statements. This final order had been appealed
       to the Travis County District Court. In May 2003, the District Court
       upheld the PUCT's final order. The plaintiffs appealed the District
       Court's decision to the Third Court of Appeals.

       TCC Fuel Reconciliation

       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 and hearings were held 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. Based upon the PUCT's
       remand of certain TNC issues, TCC established an additional reserve of $9
       million in the second quarter of 2003. An adverse ruling from the PUCT in
       excess of the reserves 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 7
       "Customer Choice and Industry Restructuring".

       SWEPCo Fuel Reconciliation

       In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs. This
       reconciliation covers the period of January 2000 through December 2002.
       At December 31, 2002, SWEPCo's filing detailed a $2.2 million
       over-recovery balance including interest. During the reconciliation
       period, SWEPCo incurred $434.8 million of eligible fuel expense. An
       adverse ruling from the PUCT could have a material impact on future
       results of operations, cash flows and financial condition.

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

       Several parties including the Office of Public Utility Counsel (OPC) and
       cities served by both TCC and TNC appealed the PUCT's December 2001
       orders establishing initial PTB fuel factors for Mutual Energy CPL and
       Mutual Energy WTU. On June 25, 2003, the District Court ruled in both
       appeals. The Court ruled in the Mutual Energy WTU case that the PUCT
       lacked sufficient evidence to include unaccounted for energy in the fuel
       factor, erred in including unaccounted for energy in the PTB rate based
       on its treatment in other proceedings and that the PUCT had improperly
       shifted the burden of proof from the utility to the intervening parties
       in not adjusting projected generation requirements for loss of load. The
       Court upheld the initial PTB orders on all other issues. In the Mutual
       Energy CPL proceeding, the Court ruled that the PUCT should have adjusted
       projected generation requirements for the loss of load due to retail
       competition. The Court remanded the cases to the PUCT for further
       proceedings consistent with its ruling. The amount of unaccounted for
       energy built into the PTB fuel factors was approximately $2.7 million for
       Mutual Energy WTU. At this time, management is unable to estimate the
       potential financial impact related to the loss of load issue. Management
       will appeal the District Court decisions and believes, based on the
       advice of counsel, that the PUCT's original decision will ultimately be
       upheld. If the District Court's decisions are ultimately upheld the PUCT
       could reduce the PTB fuel factors charged to retail customers in 2002 and
       2003 resulting in an adverse effect on future results of operations and
       cash flows.

       Unbundled Cost of Service (UCOS) Appeal

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

       McAllen Rate Review

       On June 26, 2003, the City of McAllen requested that TCC provide
       justification showing that its transmission and distribution rates should
       not be reduced. Other municipalities served by TCC have passed similar
       rate review resolutions. In Texas, municipalities have original
       jurisdiction over rates of electric utilities within their municipal
       limits. Under Texas law, TCC has a minimum of 120 days to provide support
       for its rates to the municipalities. TCC has the right to appeal any rate
       change by the municipalities to the PUCT. Pursuant to an agreement with
       the cities, TCC will file the requested support for its rates with both
       the cities and the PUCT on November 3, 2003. Management believes that a
       rate reduction is not justified.

       Louisiana Fuel Audit

       As a result of complaints filed by customers, the LPSC is performing an
       audit of SWEPCo's fuel rates. Five SWEPCo customers filed a suit in the
       Caddo Parish District Court in January 2003 and filed a complaint with
       the LPSC. The customers claim that SWEPCo has over charged them for fuel
       costs since 1975. Management believes that SWEPCo's fuel rates prior to
       1999 were proper and have been approved by the LPSC. If the LPSC or the
       Court rules against SWEPCo, it could have an adverse impact on results of
       operations and cash flows.

       FERC Wholesale Fuel Complaints

       As discussed in the 2002 Annual Report (as updated by the Current Report
       on Form 8-K dated May 14, 2003), 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 was filed
       at FERC in June 2003 regarding the fuel complaint and new contracts.
       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. TNC anticipates that the provision
       for refund will be adequate to cover the financial implications resulting
       from these new contracts. Should FERC fail to approve the settlement and
       new contracts, the actual refund and final resolution of this matter
       could differ materially from the provision and may have a negative impact
       on future results of operations, cash flows and financial condition.

       Environmental Surcharge Filing

       In September 2002, KPCo filed with the KPSC to revise its environmental
       surcharge tariff (annual revenue increase of approximately $21 million)
       to recover the cost of emissions control equipment being installed at Big
       Sandy Plant. See NOx Reductions in Note 8.

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

       PSO Rate Review

       In February 2003, the Director of the Oklahoma Corporation Commission
       (OCC) filed an application requiring PSO to file all documents necessary
       for a general rate review before August 1, 2003. The required date to
       file the case was subsequently changed to October 31, 2003. Management is
       unable to predict the ultimate effect of this review on PSO's rates.

       PSO Fuel and Purchased Power

       As discussed in Note 6 of the 2002 Annual Report (as updated by the
       Current Report on Form 8-K dated May 14, 2003), PSO had a $44 million
       under-recovery of fuel costs resulting from a reallocation of purchased
       power costs for periods prior to January 1, 2002. On July 23, 2003, PSO
       filed with the OCC seeking recovery of the $44 million over an eighteen
       month time period. A hearing has been scheduled for October 7, 2003. If
       the OCC does not permit recovery, there will be an adverse effect on
       results of operations, cash flows and possibly financial condition.

       Virginia Fuel Factor Filing

       APCo filed with the Virginia SCC to reduce its fuel factor effective
       August 1, 2003. The requested fuel rate reduction would be effective for
       17 months and is estimated to reduce revenues by $36 million. By order
       dated July 23, 2003, the Virginia SCC approved APCo's requested fuel
       factor reduction on an interim basis, subject to further investigation.
       This fuel factor adjustment will reduce cash flows without impacting
       results of operations as any over-recovery of fuel costs would be
       deferred as a regulatory liability.

       FERC Long-term Contracts

       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 into 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, we 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.

       RTO Formation/Integration Costs

       With FERC approval, AEP East companies have been deferring costs incurred
       under FERC orders to form an RTO (the Alliance RTO) or join an existing
       RTO (PJM). On July 2, 2003, the FERC issued an order approving our
       continued deferral of both our Alliance formation costs and our PJM
       integration costs including the deferral of a carrying charge. The AEP
       East companies have deferred approximately $22 million of RTO formation
       and integration costs and related carrying charges through June 30, 2003.
       As a result of the subsequent delay in the integration of AEP's East
       transmission system into PJM, FERC declined to rule, at this time, on our
       request to transfer the deferrals to regulatory assets, and to maintain
       the deferrals until such time as the costs can be recovered from all
       users of AEP's East transmission system. The AEP East companies will
       apply for permission to transfer the deferred formation/integration costs
       to a regulatory asset prior to integration with PJM.

       In the first quarter of 2003, the state of Virginia enacted legislation
       preventing APCo from joining an RTO until after June 30, 2004 and only
       then with the approval of the Virginia SCC. In the second quarter of
       2003, the KPSC denied KPCo's request that they approve our joining PJM
       based in part on a lack of evidence that it would benefit Kentucky retail
       customers. Management intends to seek a rehearing in Kentucky. Management
       does not expect the integration with PJM to occur prior to June 30, 2004.
       In its July 2 order, FERC indicated that it would review the deferred
       costs for prudency at the time they are transferred to a regulatory asset
       account and scheduled for amortization and recovery in the open access
       transmission tariff (OATT) to be charged by PJM. Management believes that
       the FERC will grant permission for the deferred RTO costs to be amortized
       and included in the OATT.

       Whether the amortized costs will be fully recoverable depends upon the
       state regulatory commissions' treatment of AEP's East companies' portion
       of the OATT at the time they join PJM. Presently, retail rates are frozen
       or capped and cannot be increased for retail customers of CSPCo, I&M and
       OPCo. We intend to apply with FERC seeking permission to delay the
       amortization of the deferred RTO formation/integration costs until they
       are recoverable from all users of the transmission system including
       retail customers. Management is unable to predict the timing of when AEP
       will join PJM and if upon joining PJM whether FERC will grant a delay of
       recovery until the rate caps and freezes end. Management intends to seek
       recovery of the deferred RTO formation/integration costs. If the FERC
       ultimately decides not to approve a delay or the state commissions deny
       recovery, future results of operations and cash flows could be adversely
       affected.

       FERC Order on Regional Through and Out Rates (RTOR)

       On July 23, 2003, the FERC issued an order directing PJM and the Midwest
       ISO to make compliance filings for their respective Open Access
       Transmission Tariffs to eliminate, by November 1, 2003, the Regional
       Through and Out Rates (RTOR) on transactions where the energy is
       delivered within the Midwest ISO and PJM regions. The elimination of the
       RTORs will reduce the transmission service revenues collected by the RTOs
       and thereby reduce the revenues received by transmission owners under the
       RTOs' revenue distribution protocols. The order provided that affected
       Transmission Owners could file to offset the elimination of these
       revenues by increasing rates or utilizing a transitional rate mechanism
       to recover lost revenues that result from the elimination of the RTORs.
       The FERC also found that the through and out rates of some of the former
       Alliance RTO Companies, including AEP, may be unjust, unreasonable, and
       unduly discriminatory or preferential for energy delivered in the Midwest
       ISO/PJM regions. FERC has initiated an investigation and hearing in
       regard to these rates. We will make a filing with the FERC supporting the
       justness and reasonableness of our rates by August 15, 2003. Management
       at this time is unable to predict the ultimate outcome of this
       investigation, or the impact on our results of operations and cash flows.

7.     CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
       ------------------------------------------

       As discussed in the 2002 Annual Report (as updated by the Current Report
       on Form 8-K dated May 14, 2003), retail customer choice began in four of
       the eleven state retail jurisdictions (Michigan, Ohio, Texas and
       Virginia) in which the AEP domestic electric utility companies operate.
       The following paragraphs discuss significant events occurring in 2003
       related to customer choice and industry restructuring.

       Ohio Restructuring

       On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy
       Users-Ohio and American Municipal Power-Ohio filed a complaint with the
       PUCO alleging that CSPCo and OPCo have violated the PUCO's orders
       regarding implementation of their transition plan and violated other
       applicable law by failing to participate in an RTO.

        The complainants seek, among other relief, an order from the PUCO:
            o  suspending collection of transition charges by CSPCo and OPCo
               until transfer of control of their transmission assets has
               occurred
            o  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. CSPCo and OPCo filed
        comments and responses in compliance with the PUCO's schedule.
        Management is unable to predict the timing or the outcome of this
        proceeding.

        The Ohio Act provides for a Development Period during which retail
        customers can choose their electric power suppliers or have the
        protection of Default Service at frozen generation rates from the
        incumbent utility. The Development Period began on January 1, 2001 and
        will terminate no later than December 31, 2005, but the PUCO may
        terminate the Development Period for one or more customer classes before
        that date if it determines either that effective competition exists in
        the incumbent utility's certified territory or that there is a twenty
        percent switching rate of the incumbent utility's load by customer
        class. Following the Development Period, retail customers will receive
        distribution and transmission service from the incumbent utility whose
        distribution rates will be approved by the PUCO and whose transmission
        rates will be approved by the FERC. Retail customers will continue to
        have the right to choose their electric power suppliers or have the
        protection of Default Service which must be offered by the incumbent
        utility at market rates. The PUCO has circulated a draft of proposed
        rules but has not yet identified the method by which it will determine
        market rates for Default Service following the Development Period.

        As provided in the stipulation agreement approved by the PUCO, we are
        deferring customer choice implementation costs in excess of $40 million.
        The agreements provide for the deferral of these costs as a regulatory
        asset until the next distribution base rate case. We have deferred $22
        million of such costs. Recovery of these regulatory assets will be
        subject to PUCO review in our next Ohio distribution rate filings which
        will not occur until after 2008 for CSPCo and 2007 for OPCo. Management
        believes that the amounts deferred represent prudently incurred customer
        choice implementation costs and should be recoverable in future rates,
        If the PUCO determines that any of the deferred costs are unrecoverable,
        it would have an adverse impact on future results of operations and cash
        flows.

        Texas Restructuring

        As discussed in the 2002 Annual Report (as updated by the Current Report
        on Form 8-K dated May 14, 2003), 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), a true-up of the power costs used in the PUCT's ECOM model
        for 2002 and 2003 to reflect actual market prices determined through
        legislatively-mandated capacity auctions (Wholesale capacity auction
        true-up) 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 review in the 2004 true-up
        proceedings. The PUCT adopted a rule 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 wholesale capacity auction true-up adjustment for
        TCC for the 2004 true-up proceeding.

        The decision to determine stranded costs by selling TCC's generating
        plants and the expectation that the sales price would produce a
        significant loss/stranded costs instead of using the PUCT's ECOM model
        estimates, enabled TCC to record in 2002 a $262 million regulatory asset
        and related revenues which represents the quantifiable amount of the
        wholesale capacity auction true-up for the year 2002. Through June 30,
        2003, TCC recorded an additional $108 million regulatory asset and
        related revenues for wholesale capacity auction true-up. 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 they can not be recovered unless there are stranded costs.
        As discussed above, a defined process is required in order to determine
        the amount of stranded costs related to generation facilities for the
        2004 true-up proceedings.

        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 competition transition charge to T&D utility customers.

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

        Arkansas Restructuring

        In February 2003, Arkansas repealed customer choice legislation
        originally enacted in 1999. Consequently, SWEPCo's Arkansas operations
        reapplied SFAS 71 regulatory accounting which had been discontinued in
        1999. The reapplication of SFAS 71 had an insignificant effect on
        results of operations for the first six months 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

        APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the
        first quarter of 2003 after new developments during the quarter prompted
        an analysis of the probability of restructuring becoming effective.

        In 2000, the WVPSC issued an order approving an electricity
        restructuring plan, which the WV Legislature approved by joint
        resolution. The joint resolution provided that the WVPSC could not
        implement the plan until the WV legislature made tax law changes
        necessary to preserve the revenues of state and local governments.

        In the 2001 and 2002 legislative sessions, the WV Legislature failed to
        enact the required legislation that would allow the WVPSC to implement
        the restructuring plan. Due to this lack of legislative activity, the
        WVPSC closed two proceedings related to electricity restructuring during
        the summer of 2002.

        In the 2003 legislative session, the WV Legislature failed to enact the
        required tax legislation. Also, 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
        restructuring in WV was no longer probable and confirmed facts relating
        to the WVPSC's jurisdiction and rate authority over APCo's WV
        generation. APCo has concluded that deregulation of the WV generation
        business is no longer probable and operations in WV meet the
        requirements to reapply SFAS 71.

        The result of reapplying SFAS 71 in WV had an insignificant effect on
        results of operations during the first six months 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
        marked-to-market.

8.      COMMITMENTS AND CONTINGENCIES
        -----------------------------

        Power Generation Facility

        AEP has agreements with Juniper Capital L.P. (Juniper) under which
        Juniper will develop, construct, and finance a power generation facility
        (Facility) near Plaquemine, Louisiana and lease the Facility to AEP.
        Construction of the Facility was begun by Katco Funding, Limited
        Partnership (Katco), an unrelated unconsolidated special purpose entity,
        and Katco assigned its interest in the Facility to Juniper in June 2003.
        Juniper is a limited partnership, unaffiliated and unconsolidated with
        AEP, formed to construct or otherwise acquire real and personal property
        for lease to third parties, to manage financial assets and to undertake
        other activities related to asset financing. Juniper has arranged to
        finance the Facility with debt financing up to $471 million and equity
        up to $29 million (approximately 6%) of the Facility's acquisition cost
        from investors with no relationship to AEP or any of AEP's subsidiaries.
        Juniper will own the Facility and lease it to AEP after construction is
        completed. The lease will be treated as an operating lease for financial
        accounting purposes. Consequently, the Facility and the related
        obligations are not reported on AEP's consolidated balance sheet.
        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 Juniper allows AEP to limit its risk
        associated with the Facility once construction has been completed. In
        addition, the lease allows AEP to utilize certain tax benefits
        associated with the Facility.

        AEP is the construction agent for Juniper. 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 Juniper's acquisition cost (which, in general, is the
        outstanding debt and equity associated with the Facility) or terminate
        the project and make a payment to Juniper for 89.9% of project costs.

        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 has a contract to resell that energy to
        Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years.
        Beginning May 1, 2003, AEP had certain contractual rights and
        obligations in connection with providing replacement energy and other
        products to TEM. TEM has rejected the replacement energy. On June 27,
        2003, AEP and TEM signed a "standstill agreement" whereby negotiations
        will occur up to August 25, 2003. During this negotiation period, no
        power will be delivered to TEM under the contract, but both parties will
        retain all rights as if AEP offered the power and TEM rejected it. 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 initial term of the operating lease between Juniper and AEP
        commences on the commercial operation date (COD) of the Facility and
        continues for five years or, if earlier, until June 2009. The lease
        contains extension options and if all extension options were exercised,
        the total term of the lease would be 30 years. AEP's lease payments to
        Juniper during the initial term and each extended term are sufficient
        for Juniper to make required debt payments under Juniper's debt
        financing associated with the Facility and provide a return on equity to
        the investors in Juniper. AEP has the right to purchase the Facility for
        the acquisition cost during the last month of the initial term or on any
        monthly rent payment date during any extended term. In addition, AEP may
        purchase the Facility for the acquisition cost at any time during the
        initial term if AEP has arranged a sale of the Facility to an
        unaffiliated third party. A purchase of the Facility from Juniper by AEP
        would not alter DOW's rights to lease the Facility or AEP's contract to
        purchase energy from DOW. At the end of the anticipated 30-year lease
        term, AEP may renew the lease at fair market value subject to Juniper's
        approval, purchase the Facility at its original construction cost, or
        sell the Facility, on behalf of Juniper, to an independent third party.
        If the Facility is sold and the proceeds from the sale are insufficient
        to pay all of Juniper's acquisition costs, AEP may be required to make a
        payment (not to exceed $377 million) to Juniper of the excess of
        Juniper's acquisition costs over the proceeds from the sale up to
        approximately 75% of the project's cost, provided that AEP would not be
        required to make any payment if AEP has made the additional rental
        prepayment described below. AEP has guaranteed the obligations of its
        subsidiaries to Juniper during the construction and post-construction
        periods. Due to FIN 45, at COD, AEP will be required to record the fair
        value (approximately $16 million) of this guarantee as a liability with
        an offsetting asset.

        As of June 30, 2003, Juniper's project costs for the Facility totaled
        $441 million, and total costs for the completed Facility are expected to
        be approximately $500 million. For the 30-year extended lease term, the
        base lease rental is a variable rate obligation indexed to three-month
        LIBOR. Consequently as market interest rates increase, the base rental
        payments under this operating lease will also increase. Annual payments
        of approximately $16 million represent future minimum payments during
        the initial term calculated using the indexed LIBOR rate (1.12% at June
        30, 2003). An additional rental prepayment (up to $377 million as of
        June 30, 2003) may be due on June 30, 2004 unless Juniper has refinanced
        its present debt financing on a long-term basis. The Facility is
        collateral for the debt obligation of Juniper. Our maximum exposure to
        loss as a result of its involvement with Juniper is 100% of Juniper's
        acquisition costs during the construction phase and up to $377 million
        once the construction is completed. These calculations could change
        based on the final amount of total costs or changes in interest rates.
        Maximum loss is deemed to be remote due to the collateralization.

        As a result of Katco's transfer of its interest in the Facility to
        Juniper, we will not consolidate Juniper or any portion of the
        Facility in accordance with FIN 46.

        Nuclear Plant Outages

        In April 2003, engineers at STP, during inspections conducted regularly
        as part of refueling outages, found wall cracks in two bottom mounted
        instrument guide tubes of STP Unit 1. These cracks have been repaired
        and the unit is expected to return to service in late summer. Our share
        of the direct cost of repair was approximately $6 million through June
        30, 2003. STP officials are working closely with the NRC to safely
        return the unit to service. We have commitments to provide power to
        customers during the outage. Therefore, we will be subject to
        fluctuations in the market prices of electricity and purchased
        replacement energy could be a significant cost.

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

        Federal EPA Complaint and Notice of Violation

        As discussed in Note 9 of the Combined Notes to Financial Statements in
        the 2002 Annual Report (as updated by the Current Report on Form 8-K
        dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
        Proceedings", 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 our 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

        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 our 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, our 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 requirements began in May 2003
        for TCC and begin in May 2005 for SWEPCo.

        We are 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. In May 2003,
        SCR technology installed at Big Sandy and Cardinal plants commenced
        operation. 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.

        Our 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.
        Current estimates indicate that our 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 $976 million has been spent through
        June 30, 2003. 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

        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 our 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 our financial position, results of operations and cash
        flows.

        During 2002 and 2001, we expensed a total of $53 million ($34 million
        net of tax) for our estimated loss from the Enron bankruptcy. The amount
        expensed was based on an analysis of contracts where AEP and Enron
        entities are counterparties, the offsetting of receivables and payables,
        the application of deposits from Enron entities and management's
        analysis of the HPL related purchase contingencies and indemnifications.

        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. In
        this regard in July 2003, Enron sent to AEPES a demand for payment of
        approximately $138 million relating to AEPES' termination of trading
        contracts which amount does not recognize the right of setoff, discussed
        above. 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

        In the fourth quarter of 2002 and the first quarter of 2003, lawsuits
        alleging securities law violations and seeking class action
        certification were filed in federal District Court, Columbus, Ohio
        against AEP, certain AEP executives, and in some of the lawsuits,
        members of the AEP Board of Directors and certain investment banking
        firms. The lawsuits claim that we failed to disclose that alleged "round
        trip" trades resulted in an overstatement of revenues, that we failed to
        disclose that our traders falsely reported energy prices to trade
        publications that published gas price indices and that we failed to
        disclose that we did not have in place sufficient management controls to
        prevent round trip trades or false reporting of energy prices. The
        plaintiffs seek recovery of an unstated amount of compensatory damages,
        attorney fees and costs. The Court has appointed a lead plaintiff and
        allowed the lead plaintiff the opportunity to file an amended complaint.
        Also, in the first quarter of 2003, a lawsuit making essentially the
        same allegations and demands was filed in state Common Pleas Court,
        Columbus, Ohio against AEP, certain executives, members of the Board of
        Directors and our independent auditor. We removed this case to federal
        District Court in Columbus. The case is pending on plaintiff's motion to
        remand. We intend to vigorously defend against these actions.

        In the fourth quarter of 2002, two shareholder derivative actions were
        filed in state court in Columbus, Ohio against AEP and its Board of
        Directors alleging a breach of fiduciary duty for failure to establish
        and maintain adequate internal controls over our gas trading operations.
        Also, in the fourth quarter of 2002 and the first quarter of 2003, three
        lawsuits were filed against AEP, certain executives and AEP's Employee
        Retirement Income Security Act (ERISA) Plan Administrator alleging
        violations of ERISA in the selection of AEP stock as an investment
        alternative and in the allocation of assets to AEP stock. The ERISA
        actions are pending in federal District Court, Columbus, Ohio. The
        derivative actions and the ERISA actions are in the initial pleading
        stage. We intend to vigorously defend against these actions.

        California Lawsuit

        In November 2002, the Lieutenant Governor of California filed a lawsuit
        in Los Angeles County, California Superior Court against forty energy
        companies, including AEP, and two publishing companies alleging
        violations of California law through alleged fraudulent reporting of
        false natural gas price and volume information with an intent to affect
        the market price of natural gas and electricity. This case is in the
        initial pleading stage and all defendants have filed motions to dismiss.
        The plaintiff has moved to dismiss us and has stated an intention to
        amend the complaint to add an AEP subsidiary as a defendant. We intend
        to vigorously defend against this action.

        Texas Commercial Energy, LLP Lawsuit

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

        Bank of Montreal Claim

        In March 2003, Bank of Montreal (BOM) terminated all natural gas trading
        deals and claimed approximately $34 million was owed to BOM by AEP. In
        April 2003, we 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 us
        approximately $68 million. Alternatively, we are claiming that BOM owes
        us approximately $45 million. Although management is unable to predict
        the outcome of this matter, it is not expected to have a material impact
        on results of operations, cash flows or financial condition.

        Arbitration of Williams Claim

        In October 2002, we filed a demand for arbitration with the American
        Arbitration Association to initiate formal arbitration proceedings in a
        dispute with the Williams Companies (Williams). The proceeding 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 we owed approximately $130 million in connection
        with the termination and liquidation of all trading deals. Williams and
        AEP settled the dispute and we paid $90 million to Williams in June
        2003. The resolution of this matter did not have a material impact on
        results of operations or financial condition as we had accrued the
        amount paid.

        Arbitration of PG&E Energy Trading, LLC Claim

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

        Energy Market Investigation

        As discussed in the 2002 Annual Report (as updated by the Current Report
        on Form 8-K dated May 14, 2003), 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. Management responded to the inquiries and
        provided the requested information and has continued to respond to
        supplemental data requests in 2003.

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

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

        FERC Proposed Standard Market Design

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

        FERC Proposed Security Standards

        As part of the SMD proposed rulemaking, in July 2002, FERC published for
        comment proposed security standards. These standards were intended to
        ensure that all market participants would have a basic security program
        that would effectively protect the electric grid and related market
        activities. As proposed, these standards would apply to AEP's power
        transmission systems, distribution systems and related areas of
        business. The proposed standards have not been adopted. Subsequently, in
        2002, the North American Electric Reliability Council (NERC), with
        FERC's support, developed a new set of standards to address industry
        compliance. These new standards closely parallel the initial, proposed
        FERC standards in both content and compliance time frames, and were
        approved by the NERC ballot body in June of 2003. We are developing
        financial requirements for security implementation and compliance with
        these NERC standards. Since these financial requirements are not yet
        determined, management cannot predict the impacts of such standards on
        future results of operations and cash flows.

  9.    GUARANTEES
        ----------

        In November 2002, the FASB issued FIN 45 which clarifies the accounting
        to recognize a liability related to issuing a guarantee, as well as
        additional disclosures of guarantees. 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 were
        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 guarantees entered into prior to
        December 31, 2002 in accordance with FIN 45. There are certain
        liabilities recorded for guarantees entered into subsequent to December
        31, 2002. These liabilities are immaterial to AEP. There is no
        collateral held in relation to any guarantees and there is no recourse
        to third parties in the event any guarantees are drawn unless specified
        below.

        Certain of our 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 by an AEP subsidiary in
        the subsidiaries' ordinary course of business. TCC issued an LOC for
        credit enhancement of issued bonds. At June 30, 2003, the maximum future
        payments of all the LOCs are approximately $163 million with maturities
        ranging from July 2003 to January 2011. TCC's LOC was for approximately
        $40.9 million with a maturity date of November 2003. Since we are the
        parent to all these subsidiaries, we hold all assets of the subsidiaries
        as collateral. There is no recourse to third parties in the event these
        letters of credit are drawn.

        The following subsidiaries have entered into guarantees of third-party
        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 a financing. In the event that
        Sweeny does not make the required debt payments, CSW Energy and CSW
        International have a maximum future payment exposure of approximately
        $3.7 million, which expires June 2020.

        Additionally, AEP Utilities 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, AEP Utilities 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 obligations under a revolving credit
        agreement, capital lease obligations, and term loan payments of the
        mining contractor, Sabine Mining Company (Sabine). In the event Sabine
        defaults under any of these agreements, SWEPCo's total future maximum
        payment exposure is approximately $61 million with maturity dates
        ranging from June 2005 to February 2012.

        As part of the process to receive a renewal of a Texas Railroad
        Commission permit for lignite mining, SWEPCo has agreed to provide
        guarantees of mine reclamation in the amount of approximately $85
        million. Since SWEPCo uses self-bonding, the guarantee provides for
        SWEPCo to commit to use its resources to complete the reclamation in the
        event the work is not completed by a third party miner. At June 30,
        2003, the cost to reclaim the mine in 2035 is estimated to be
        approximately $36 million. This guarantee ends upon depletion of
        reserves estimated at 2035 plus 6 years to complete reclamation.

        It is reasonably possible that due to the guarantees and contracts in
        place with Sabine that SWEPCo will consolidate Sabine in the third
        quarter of 2003, as a result of the issuance of FIN 46. Upon
        consolidation, SWEPCo would record the assets, liabilities, depreciation
        expense, minority interest and debt interest expense of Sabine. SWEPCo
        would eliminate expenses associated with the mining contract against
        Sabine's revenues.

        See Note 8 "Commitments and Contingencies" under Power Generation
        Facility for disclosure of related guarantees. See Note 13 "Leases" for
        disclosure of lease residual value guarantees. See Note 14 "Minority
        Interest in Finance Subsidiary" for disclosure of related guarantees.

        We entered into several types of contracts, which would require
        indemnifications. Typically these contracts include, but are not limited
        to, sale agreements, lease agreements, purchase agreements and financing
        agreements. Generally these agreements may include, but are not limited
        to, indemnifications around certain tax, contractual and environmental
        matters. With respect to sale agreements, our exposure generally does
        not exceed the sale price. We cannot estimate the maximum potential
        exposure for any of these indemnifications entered prior to December 31,
        2002 due to the uncertainty of future events. In the first and second
        quarters of 2003, we entered into several sale agreements as discussed
        in Note 11. These sale agreements include indemnifications with a
        maximum exposure of approximately $67 million. There are no material
        liabilities recorded for any indemnifications entered during the first
        six months of 2003. There are no liabilities recorded for any
        indemnifications entered prior to December 31, 2002.

        We lease certain equipment under a master operating lease. Under the
        lease agreement, the lessor is guaranteed to receive up to 87% of the
        unamortized balance of the equipment at the end of the lease term. If
        the fair market value of the leased equipment is below the unamortized
        balance at the end of the lease term, we have committed to pay the
        difference between the fair market value and the unamortized balance,
        with the total guarantee not to exceed 87% of the unamortized balance.
        At June 30, 2003, the maximum potential loss for these lease agreements
        was approximately $27 million assuming the fair market value of the
        equipment is zero at the end of the lease term.

10.     SUSTAINED EARNINGS IMPROVEMENT INITIATIVE
        -----------------------------------------

        In response to difficult conditions in our business, a Sustained
        Earnings Improvement (SEI) initiative was undertaken company-wide in the
        fourth quarter of 2002, as a cost-saving and revenue-building effort to
        build long-term earnings growth.

        Termination benefits expense relating to 1,120 terminated employees
        totaling $75.4 million pre-tax was recorded in the fourth quarter of
        2002. Of this amount, we paid $9.5 million and $51.2 million to these
        terminated employees in the fourth quarter of 2002 and the first
        quarter of 2003, respectively. Substantially all SEI related payments
        have been made as of June 30, 2003.  The termination benefits expense
        was classified as Maintenance and Other Operation expense on our
        Consolidated Statements of Operations. No additional termination
        benefits expense related to the SEI initiative was recorded during
        the first and second quarters of 2003.

11.     DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE
        --------------------------------------------------------------

        DISPOSITIONS

        First Quarter 2003 Dispositions

        We completed the sales of C3 Communications, Mutual Energy Service
        Company, LLC, our water heater rental program assets and our interest in
        AEP Gas Power Systems, LLC. The impact on our results of operations for
        the six months ended June 30, 2003 was not significant.

        Newgulf Facility

        We completed the sale of the Newgulf facility during the second quarter
        of 2003 and the impact on earnings was not significant. Newgulf's
        Property, Plant and Equipment, net of accumulated depreciation, was
        classified on our Consolidated Balance Sheets as held for sale at
        December 31, 2002. See the tables at the end of the Assets Held for Sale
        section for more detailed information.

        Nordic Trading

        The transfer of the Nordic Trading business, including its trading
        portfolio, to new owners was completed during the second quarter of 2003
        and the impact on earnings during the second quarter of 2003 was not
        significant. The assets and liabilities of Nordic Trading were
        classified on our Consolidated Balance Sheets as held for sale at
        December 31, 2002. See the tables at the end of the Assets Held for Sale
        section for more detailed information.

        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 our 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):

        For the quarter ended June 30, 2003 and 2002:

<TABLE>
<CAPTION>

                                                                                  Pushan Power
                                             SEEBOARD           CitiPower             Plant               Eastex          Total
                                             --------           ---------         ------------            ------          -----
                                                                                  (in millions)



        <S>                                      <C>                <C>                 <C>                 <C>            <C>
        2003 Revenue                             $ -                $  -                $12                 $ 15           $ 27
        2002 Revenue                              311                 109                11                   16            447

        2003 Earnings
         (Loss) After Tax                        $ -                $  -                $(1)                 $(6)          $ (7)
        2002 Earnings
         (Loss) After Tax                           3                 (97)                1                   (3)           (96)

</TABLE>
<TABLE>
<CAPTION>

        For the six months ended June 30, 2003 and 2002:


                                                                                     Pushan Power
                                           SEEBOARD            CitiPower                 Plant              Eastex           Total
                                           --------            ---------             ------------           ------           -----
                                                                                    (in millions)

        <S>                                  <C>                <C>                      <C>                 <C>              <C>
        2003 Revenue                         $ -                $  -                     $27                 $ 46             $ 73
        2002 Revenue                          694                 206                     26                   28              954

        2003 Earnings
         (Loss) After Tax                    $ -                $  -                     $(1)                $(15)            $(16)
        2002 Earnings
         (Loss) After Tax                      36                (108)                     3                   (5)             (74)

</TABLE>

        ASSETS HELD FOR SALE

        As discussed in the 2002 Annual Report (as updated by the Current Report
        on Form 8-K dated May 14, 2003), during 2002, we recorded an estimated
        loss on disposal of assets held for sale. The following provides an
        update of those assets still held for sale.


        Eastex

        We currently anticipate that the sale of assets will be completed by the
        end of 2003. 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 our Consolidated Balance
        Sheets as held for sale. See the tables at the end of this section for
        more detailed information.

        Pushan Power Plant

        We currently anticipate that negotiations to sell our interest in the
        Pushan Power Plant (Pushan) in Nanyang, China to one of the minority
        interest partners will be completed by the second quarter of 2004. This
        anticipated closing date is later than originally expected due to
        several unusual circumstances including the SARS outbreak. 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 our Consolidated Balance Sheets as held for sale. See
        the tables at the end of this section for more detailed information.

        Excess Equipment

        In November 2002, as a result of a cancelled development project, we
        obtained title to a surplus gas turbine generator. We have 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. The Other Assets have been classified
        on our 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, we began to market an under-utilized
        office building in Dallas, TX obtained through the merger with CSW. We
        currently anticipate the sale of the facility to be completed by the end
        of 2003. The property asset has been classified on our Consolidated
        Balance Sheets as held for sale. See the tables at the end of this
        section for more detailed information.

        The assets and liabilities of the entities held for sale at June 30,
        2003 and December 31, 2002 are as follows:

<TABLE>
<CAPTION>

                                                         Pushan Power        Excess           Excess
                                             Eastex         Plant          Real Estate       Equipment      Total
                 June 30, 2003               ------      ------------      -----------       ---------      ----
                 -------------                                            (in millions)

                 Assets:
                 <S>                            <C>        <C>                <C>              <C>          <C>
                  Current Assets                $20        $ 22               $ -              $ -          $ 42
                  Property, Plant and
                   Equipment, Net                 -         147                18                -           165
                  Other Assets                    -          -                  -               12            12
                                                ---         ---               ---              ---          ----
                    Total Assets
                 Held for Sale                  $20        $169               $18              $12          $219
                                                ===        ====               ===              ===          ====
                 Liabilities:
                  Current Liabilities           $ 9        $ 21               $ -              $ -          $ 30
                  Long-term Debt                  -          22                 -                -            22
                  Other Liabilities               -          51                 -                -            51
                                                ---        ----               ---              ---          ----
                    Total Liabilities
                      Held For Sale             $ 9        $ 94               $ -              $ -          $103
                                                ===        ====               ===              ===          ====
</TABLE>
<TABLE>
<CAPTION>


                                       Pushan                             Excess                 Water       Tele-
                                       Power     Newgulf     Nordic       Real        Excess     Heater      communica-
                            Eastex     Plant     Facility    Trading      Estate      Equipment  Program     tions       Total
                            ------     -----     --------    -------      ------      ---------  -------     ----------  -----
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>


12.     BUSINESS SEGMENTS
        -----------------

         Our segments and their related business activities are as follows:

         Utility Operations
          o Domestic generation of electricity for sale to retail and wholesale
            customers
          o Domestic electricity transmission and distribution
          o Parent company, which includes corporate related expenditures,
            interest income and interest expense

         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


        The tables below present segment information for the six months ended
        June 30, 2003 and 2002. These amounts include certain estimates and
        allocations where necessary.

<TABLE>
<CAPTION>

                                                                          Investments
                                                        ------------------------------------------
                                              Utility        Gas             UK                          Reconciling
                                             Operations   Operations     Operations         Other        Adjustments  Consolidated
                                             ----------   ----------     ----------         -----        -----------  ------------
        June  30, 2003                                                         (in millions)
        Revenues from:
        <S>                                   <C>           <C>            <C>              <C>             <C>           <C>
          External Customers                  $ 5,401       $1,931         $  112           $  305          $-            $ 7,749
          Other Operating Segments               -             100           -                  28           (128)           -
        Discontinued Operations                  -            -              -                 (16)          -                (16)
        Cumulative Effect of
         Accounting Changes,
         net of tax                               238          (23)           (22)            -              -                193
        Net Income (Loss)                         750          (61)           (59)             (15)          -                615
        Total Assets                           28,539        3,492          1,295            1,814            219 (a)      35,359
</TABLE>
<TABLE>
<CAPTION>


                                                                           Investments
                                                        -------------------------------------------
                                            Utility        Gas              UK                          Reconciling
                                           Operations   Operations      Operations           Other      Adjustments   Consolidated
                                           ----------   ----------      ----------         --------     -----------   ------------

        June 30, 2002
<S>                                         <C>             <C>            <C>             <C>              <C>           <C>

        Revenues from:
          External Customers                $ 4,918         $1,103         $  134          $   418          $-            $ 6,573
          Other Operating Segments             -               134           -                  78           (212)           -
        Discontinued Operations                -              -              -                 (74)          -                (74)
        Cumulative Effect of
         Accounting Changes,
         net of tax                            -              -              -                (350)          -               (350)
        Net Income (Loss)                       441            (80)            11             (479)          -               (107)
        Total Assets                         25,797          5,387          1,707            7,067            844 (a)      40,802
</TABLE>

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

13.     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 June 30, 2003, AEP has determined that OPCo will consolidate JMG in
        the third quarter of 2003 as a result of the issuance of FIN 46. Upon
        consolidation, OPCo will record the assets, liabilities, depreciation
        expense, minority interest and debt interest expense of JMG. OPCo will
        eliminate operating lease expense against JMG's rental revenues. As of
        June 30, 2003, the Company is still reviewing the impact of the
        consolidation, but will have to record the cumulative effect (net of
        tax) due to a change in accounting principle. 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 June 30, 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." The asset will be amortized over the
        remaining lease term, which ends in the first quarter of 2010.

        See Note 8 "Commitments and Contingencies" under Power Generation
        Facility for discussion of its lease.

        In June 2003, we entered into an agreement with an unrelated,
        unconsolidated leasing company to lease 875 coal-transporting aluminum
        railcars. The lease has an initial term of five years and may be renewed
        for up to three additional five-year terms, for a maximum of twenty
        years. We intend to renew the lease for the full twenty years. At the
        end of each lease term, we may (a) renew for another five-year term, not
        to exceed a total of twenty years, (b) purchase the railcars for the
        purchase price amount specified in the lease, projected at the lease
        inception to be the then fair market value, or (c) return the railcars
        and arrange a third party sale (return-and-sale option). The lease is
        accounted for as an operating lease with the future payment obligations
        included in the annual lease footnote.

        This operating lease agreement allows us to avoid a large initial
        capital expenditure, and to spread our railcar cost evenly over the
        expected twenty-year usage period. In addition, the lease allows us to
        take the income tax benefits otherwise associated with ownership.

        Under the lease agreement, the lessor is guaranteed that the sale
        proceeds under the return-and-sale option discussed above will equal at
        least a lessee obligation amount specified in the lease, which declines
        over time from approximately 86% to 77% of the projected fair market
        value of the equipment. At June 30, 2003, the maximum potential loss was
        approximately $31.5 million ($20.5 million net of tax) assuming the fair
        market value of the equipment is zero at the end of the current lease
        term. The railcars are subleased for one year to an unaffiliated company
        under an operating lease. The sublessee may renew the lease for up to
        four additional one-year terms.

14.     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 and Louisiana Intrastate 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 was convertible into AEP common stock at market
        price on a dollar-for-dollar basis. Caddis was capitalized with $2
        million cash and a subscription agreement that represents an
        unconditional obligation to fund $83 million from SubOne for a managing
        member interest and $750 million from Steelhead Investors LLC
        (Steelhead) for a non-controlling preferred member interest. As managing
        member, SubOne consolidates Caddis. Steelhead is an unconsolidated
        special purpose entity and had an original 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 $750 million invested in Caddis by Steelhead was loaned to SubOne.
        This intercompany loan to SubOne is due August 2006.

        On May 9, 2003, SubOne borrowed $225 million from AEP and used the
        proceeds to reduce the outstanding balance of the loan from Caddis,
        which Caddis used to reduce the preferred interest held by Steelhead.
        This payment eliminated the convertible preferred stock of AEP Gas
        Holding and the stock price trigger. The use of Steelhead originally
        allowed 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 (5.25% and 4.73% for the quarters ended June 30, 2003 and
        2002, respectively). Caddis has the right to redeem Steelhead's interest
        at any time.

        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 June 30, 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. 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 Operations and Consolidated Balance
        Sheets as Minority Interest in Finance Subsidiary.

        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 $207 million (as of June
        30, 2003) due Caddis for default under the intercompany loan agreement.
        The recourse to AEP for the second quarter will increase in the third
        quarter 2003 to the full $525 million in order to comply with the
        covenants.

        The FASB and other accounting constituencies continue to interpret the
        application of FIN 46 and SFAS 150.  As a result, AEP is continuing to
        review the application of these new standards as they relate to the
        Steelhead transaction.

15.     FINANCING AND RELATED ACTIVITIES
        --------------------------------
<TABLE>
<CAPTION>

        Long-term debt and other securities issuances and retirements during the
        first six months of 2003 were:

                                       Type                    Principal     Interest                Due
           Company                    of Debt                   Amount         Rate                 Date
           -------                    -------                 -----------    --------               ----
           Issuances                                         (in millions)     (%)
           ---------

            <S>                   <C>                           <C>           <C>                  <C>
            AEP                   Senior Unsecured Notes        $500          5.375                2010
            AEP                   Senior Unsecured Notes         300          5.25                 2015
            APCo                  Senior Unsecured Notes         200          3.60                 2008
            APCo                  Senior Unsecured Notes         200          5.95                 2033
            APCo                  Installment Purchase
                                   Contracts                     100          5.50                 2022
            CSPCo                 Senior Unsecured Notes         250          5.50                 2013
            CSPCo                 Senior Unsecured Notes         250          6.60                 2033
            KPCo                  Senior Unsecured Notes          75          5.625                2032
            OPCo                  Senior Unsecured Notes         250          5.50                 2013
            OPCo                  Senior Unsecured Notes         250          6.60                 2033
            SWEPCo                Senior Unsecured Notes         100          5.375                2015
            SWEPCo                Secured Note                    44          4.47                 2011
            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

</TABLE>
<TABLE>
<CAPTION>


                                          Type                  Principal            Interest               Due
        Company                          of Debt                  Amount                Rate                Date
        ----------                       -------                -----------           --------              ----
        Retirements                                            (in millions)            (%)
        -----------

            <S>                    <C>                             <C>                  <C>                  <C>
            AEP                    Bank Facility                   $1,300               Variable             2003
            AEP                    Senior Unsecured Notes              49               6.125                2006
            AEP                    Senior Unsecured Notes             250               5.50                 2003
            AEP                    Other Debt                           6               Variable             2005
            APCo                   First Mortgage Bonds                70               8.50                 2022
            APCo                   First Mortgage Bonds                30               7.80                 2023
            APCo                   First Mortgage Bonds                20               7.15                 2023
            APCo                   Installment Purchase
                                    Contracts                          10               7.875                2013
            APCo                   Installment Purchase
                                    Contracts                          40               6.85                 2022
            APCo                   Installment Purchase
                                    Contracts                          50               6.60                 2022
            APCo                   Senior Unsecured Notes             100               7.20                 2038
            APCo                   Senior Unsecured Notes             100               7.30                 2038
            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
            CSPCo                  First Mortgage Bonds                13               6.80                 2003
            CSPCo                  First Mortgage Bonds                26               6.55                 2004
            CSPCo                  First Mortgage Bonds                26               6.75                 2004
            CSPCo                  First Mortgage Bonds                40               7.90                 2023
            CSPCo                  First Mortgage Bonds                33               7.75                 2023
            I&M                    First Mortgage Bonds                75               8.50                 2022
            I&M                    First Mortgage Bonds                15               7.35                 2023
            I&M                    Junior Debentures                   40               8.00                 2026
            I&M                    Junior Debentures                  125               7.60                 2038
            KPCo                   Junior Debentures                   40               8.72                 2025
            OPCo                   First Mortgage Bonds                30               6.75                 2003
            PSO                    First Mortgage Bonds                35               6.25                 2003
            SWEPCo                 First Mortgage Bonds                55               6.625                2003
            SWEPCo                 Secured Note                         1               4.47                 2011
            TCC                    First Mortgage Bonds                18               7.50                 2023
            TCC                    First Mortgage Bonds                16               6.875                2003
            TCC                    Securitization Bonds                32               3.54                 2005
</TABLE>
<TABLE>
<CAPTION>

             Non-Registrant:
             <S>                   <C>                              <C>                 <C>                  <C>
             AEP Subsidiaries      Notes Payable                      3                 Variable             2003-2007
             AEP Subsidiaries      Revolving Credit
                                      Agreement                     306                 Variable             2003
             AEP Subsidiaries      Senior Unsecured Notes            17                 6.50                 2003

</TABLE>
<TABLE>
<CAPTION>


        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)         (%)
          -----------

            <S>                             <C>                           <C>              <C>                  <C>
            CSPCo                           Notes Payable                 $160             6.501                2006
            KPCo                            Notes Payable                   15             4.336                2003
            OPCo                            Notes Payable                  240             6.501                2006
            OPCo                            Notes Payable                   60             4.336                2003

            Non-Registrant:
            AEP Subsidiaries                Notes Payable                  105             4.336                2003
            AEP Subsidiaries                Notes Payable                   12             6.501                2006
</TABLE>

        Other Matters

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

        In July 2003, Ohio Power issued the following Senior Unsecured Notes:

         Principal                                             Due
          Amount                 Interest Rate                 Date
        -----------              -------------                 ----
        (in millions)                (%)

        $225 million                4.85%                      2014
        $225 million                6.375%                     2033

        Common Stock

        In March 2003, we issued 56 million shares of common stock at $20.95 per
        share through an equity offering and received net proceeds of $1,141
        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>

                            AEP GENERATING COMPANY
            MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
            --------------------------------------------------------

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 (12.16% annually) and a return on other capital, net of temporary cash
investments.

Results of Operations
---------------------

Net Income increased $50 thousand during the second quarter and decreased $47
thousand in the six month period. The fluctuations in Net Income are a result of
terms in the unit power agreements which limit recovery of return on capital
related to operating and in-service ratios of the Rockport Plant calculated and
adjusted monthly.

Operating Income

Operating Income was virtually unchanged in the quarter and increased $94
thousand year-to-date reflecting recovery in revenues of increased operating
costs in accordance with the unit power agreements.

o        Operating Revenues increased as a result of increased recoverable
         expenses, primarily fuel, as net generation increased 14% in the
         quarter and 30% year-to-date.

o        Fuel for Electric  Generation  expense  increased  due to increased
         generation  in 2003 and higher coal costs.  Outages during the first
         quarter of 2002 reduced the Rockport Plant's availability and
         generation in 2002.

o        The decreases in Other Operation and Maintenance expenses are
         primarily due to higher costs incurred during planned maintenance in
         2002.

o        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 tax law
         effective March 2002.

o        Income Taxes attributable to operations increased primarily due to
         state income tax accrual adjustments.



<PAGE>
<TABLE>
<CAPTION>


                                                                         AEP GENERATING COMPANY
                                                                          STATEMENTS OF INCOME
                                                                              (UNAUDITED)

                                                            Three Months Ended June 30,               Six Months Ended June 30,
                                                             2003                2002                   2003              2002
                                                             ----                ----                   ----              ----
                                                                                       (in thousands)

<S>                                                         <C>                 <C>                  <C>                <C>
OPERATING REVENUES                                          $59,568             $53,356              $119,996           $103,231
                                                            -------             -------              --------           --------

OPERATING EXPENSES:
   Fuel for Electric Generation                              29,237              21,535                59,634             39,035
   Rent - Rockport Plant Unit 2                              17,070              17,070                34,141             34,141
   Other Operation                                            2,443               4,014                 4,992              7,236
   Maintenance                                                2,287               2,378                 3,938              5,354
   Depreciation                                               5,665               5,642                11,286             11,275
   Taxes Other Than Income Taxes                                604                 907                 1,395              1,960
   Income Taxes                                                 748                 306                 1,245                959
                                                            -------             -------              --------           --------

          TOTAL OPERATING EXPENSES                           58,054              51,852               116,631             99,960
                                                            -------             -------              --------           --------

OPERATING INCOME                                              1,514               1,504                 3,365              3,271

NONOPERATING INCOME                                              19                  32                    21                 34

NONOPERATING EXPENSES                                            25                  94                   242                106

NONOPERATING INCOME TAX CREDITS                                 845                 823                 1,739              1,655

INTEREST CHARGES                                                585                 547                 1,319              1,243
                                                            -------             -------              --------           --------

NET INCOME                                                  $ 1,768             $ 1,718              $  3,564           $  3,611
                                                            =======             =======              ========           ========
</TABLE>
<TABLE>
<CAPTION>

                                                       STATEMENTS OF RETAINED EARNINGS
                                                                (UNAUDITED)

                                                           Three Months Ended June 30,                Six Months Ended June 30,
                                                              2003                2002                 2003                2002
                                                              ----                ----                 ----                ----
                                                                                       (in thousands)

<S>                                                         <C>                 <C>                   <C>                <C>
BALANCE AT BEGINNING OF PERIOD                              $18,788             $14,604               $18,163            $13,761

NET INCOME                                                    1,768               1,718                 3,564              3,611

CASH DIVIDENDS DECLARED                                       1,172               1,050                 2,343              2,100
                                                            -------             -------               -------            -------

BALANCE AT END OF PERIOD                                    $19,384             $15,272               $19,384            $15,272
                                                            =======             =======               =======            =======
</TABLE>

The common stock of AEGCo is wholly owned by AEP.

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

<PAGE>
<TABLE>
<CAPTION>


                                                             AEP GENERATING COMPANY
                                                                  BALANCE SHEETS
                                                                   (UNAUDITED)

                                                                                         June 30, 2003         December 31, 2002
                                                                                         -------------         -----------------
                                                                                                     (in  thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                         <C>                        <C>
   Production                                                                               $644,324                   $637,095
   General                                                                                     4,255                      4,728
   Construction Work in Progress                                                               7,923                     10,390
                                                                                            --------                   --------
        Total Electric Utility Plant                                                         656,502                    652,213
   Accumulated Depreciation                                                                  369,616                    358,174
                                                                                            --------                   --------
           NET ELECTRIC UTILITY PLANT                                                        286,886                    294,039
                                                                                            --------                   --------

OTHER PROPERTY AND INVESTMENTS                                                                   119                        119
                                                                                            --------                   --------

CURRENT ASSETS:
  Accounts Receivable - Affiliated Companies                                                  22,628                     18,454
  Fuel                                                                                        15,956                     20,260
  Materials and Supplies                                                                       5,004                      4,913
  Prepayments                                                                                     49                       -
                                                                                            --------                   --------
           TOTAL CURRENT ASSETS                                                               43,637                     43,627
                                                                                            --------                   --------

REGULATORY ASSETS                                                                              5,688                      4,970
                                                                                            --------                   --------

DEFERRED CHARGES                                                                               8,519                      6,974
                                                                                            --------                   --------

           TOTAL ASSETS                                                                     $344,849                   $349,729
                                                                                            ========                   ========
</TABLE>

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


                                                                AEP GENERATING COMPANY
                                                                    BALANCE SHEETS
                                                                     (UNAUDITED)

                                                                                         June 30, 2003            December 31, 2002
                                                                                         -------------            -----------------
                                                                                                     (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                                                           <C>                     <C>
   Common Stock - Par Value $1 per share:
      Authorized and Outstanding - 1,000 Shares                                               $ 1,000                 $  1,000
   Paid-in Capital                                                                             23,434                   23,434
   Retained Earnings                                                                           19,384                   18,163
                                                                                             --------                 --------
      Total Common Shareholder's Equity                                                        43,818                   42,597
   Long-term Debt                                                                              44,806                   44,802
                                                                                             --------                 --------

        TOTAL CAPITALIZATION                                                                   88,624                   87,399
                                                                                             --------                 --------

OTHER NONCURRENT LIABILITIES                                                                    1,297                      301
                                                                                             --------                 --------

CURRENT LIABILITIES:
   Advances from Affiliates                                                                    26,684                   28,034
   Accounts Payable:
      General                                                                                    -                          26
      Affiliated Companies                                                                     12,994                   15,907
   Taxes Accrued                                                                                6,133                    2,327
   Rent Accrued - Rockport Plant Unit 2                                                         4,963                    4,963
   Other                                                                                        1,105                    1,111
                                                                                             --------                 --------
        TOTAL CURRENT LIABILITIES                                                              51,879                   52,368
                                                                                             --------                 --------

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
 PLANT UNIT 2                                                                                 108,261                  111,046
                                                                                             --------                 --------

REGULATORY LIABILITIES:
   Deferred Investment Tax Credit                                                              51,274                   52,943
   Amounts Due to Customers for Income Taxes                                                   15,719                   16,670
                                                                                             --------                 --------
        TOTAL REGULATORY LIABILITIES                                                           66,993                   69,613
                                                                                             --------                 --------

DEFERRED INCOME TAXES                                                                          27,795                   29,002
                                                                                             --------                 --------

COMMITMENTS AND CONTINGENCIES (Note 7)

        TOTAL CAPITALIZATION AND LIABILITIES                                                 $344,849                 $349,729
                                                                                             ========                 ========
</TABLE>

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                                                   AEP GENERATING COMPANY
                                                                  STATEMENTS OF CASH FLOWS
                                                                        (UNAUDITED)

                                                                                                       Six Months Ended June 30,
                                                                                                      2003                   2002
                                                                                                      ----                   ----
                                                                                                             (in thousands)
OPERATING ACTIVITIES:
<S>                                                                                                 <C>                   <C>
   Net Income                                                                                       $ 3,564               $  3,611
   Adjustments to Reconcile Net Income to Net Cash Flows
    From Operating Activities:
     Depreciation                                                                                    11,286                 11,275
     Deferred Income Taxes                                                                           (2,158)                (2,938)
     Deferred Investment Tax Credits                                                                 (1,668)                (1,669)
     Amortization of Deferred Gain on Sale and Leaseback -
       Rockport Plant Unit 2                                                                         (2,785)                (2,785)
   Changes in Certain Assets and Liabilities:
     Accounts Receivable                                                                             (4,174)                (6,456)
     Fuel, Materials and Supplies                                                                     4,213                 (3,871)
     Accounts Payable                                                                                (2,939)                29,401
     Taxes Accrued                                                                                    3,806                  3,815
     Deferred Property Taxes                                                                         (1,573)                (1,786)
   Change in Other Assets                                                                              (751)                    43
   Change in Other Liabilities                                                                          884                    355
                                                                                                   --------               --------

           Net Cash Flows From Operating Activities                                                   7,705                 28,995
                                                                                                   --------               --------

INVESTING ACTIVITIES - Construction Expenditures                                                     (4,012)                (5,604)
                                                                                                   --------               --------

FINANCING ACTIVITIES:
     Change in Advances to/from Affiliates, net                                                      (1,350)               (22,274)
     Dividends Paid                                                                                  (2,343)                (2,100)
                                                                                                   --------               --------
           Net Cash Flows Used For Financing Activities                                              (3,693)               (24,374)
                                                                                                    -------               --------

Net Decrease in Cash and Cash Equivalents                                                              -                      (983)
Cash and Cash Equivalents at Beginning of Period                                                       -                       983
                                                                                                   --------               --------
Cash and Cash Equivalents at End of Period                                                         $   -                  $   -
                                                                                                   ========               ========
</TABLE>

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,186,000 and $1,132,000
and for income taxes was $2,448,000 and $1,217,000 in 2003 and 2002,
respectively.

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
                   AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations
---------------------

Net Income increased $70 million and $30 million for the year-to-date and second
quarter, respectively. The increased income is associated with the recognition
of stranded costs in Texas of $70 million and $34 million for the year-to-date
and second quarter, respectively.

Since REPs are the electricity suppliers to retail customers in the ERCOT area,
we sell our generation to the REPs and other market participants and provide
transmission and distribution services to retail customers of the REPs in our
service territory. As a result of the provision of retail electric service by
REPs, effective January 1, 2002, we no longer supply electricity directly to
retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in our sales as further described below.

In December 2002, AEP sold Mutual Energy 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.

Operating Income

Operating Income increased by $69 million for the year-to-date and $32 million
for the second quarter due to the following:

o        Revenues  associated  with the recovery of stranded costs in Texas,
         mentioned  above,  were $108 million for the  year-to-date  and $52
         million for the second quarter (see "Texas Restructuring" in Note 6).
o        Reliability Must Run (RMR) revenues from ERCOT of $122 million for
         the year-to-date and $66 million for the second quarter which
         include fuel recovery (see "Texas Plants" in Note 13 in the Annual
         Report, as updated by the Current Report on Form 8-K dated May 14,
         2003, for discussion of RMR facilities).
o        Increased  sales to REPs for the second quarter  consisting of an
         $11 million  increase in delivery  revenues  offset in part by a
         decrease of $7 million in generation  revenues.
o        Other generation sales increased $60 million for the year-to-date and
         $20 million for the second quarter primarily resulting from risk
         management activities.
o        Depreciation and Amortization expense decreased $7 million for the
         year-to-date and $9 million for the second quarter due mainly to
         decreases resulting from ARO (see Note 2), reduced depreciable plant
         due to the mothballing of certain generating units in 2002 and
         changes resulting from amortization of regulatory assets.
o        Reduced Taxes Other Than Income Taxes of $9 million for the year-to-
         date and $4 million for the second quarter resulting from lower
         property taxes and state gross receipts taxes stemming from
         deregulation in  Texas.

The increase in Operating Income was partially offset by:

o        Net increases in fuel and purchased power to replace portions of
         the energy from the non-RMR mothballed plants and the unscheduled
         forced outage at the STP Nuclear Unit (See "Significant Factors"
         below). KWHs purchased increased 172% while the total cost
         increased 614% due to higher average prices. This increased
         purchased power cost was offset by lower generation costs
         resulting from the reduced generation from the non-RMR mothballed
         units.
o        Increases in maintenance expense due to both the forced outage and
         a scheduled refueling outage in the first quarter at STP. The
         increase in nuclear maintenance over last year was $12 million for
         the year-to-date and $7 million for the second quarter.
o        An increase in provisions for rate refunds of $35 million for the
         year-to-date and $8 million for the second quarter (see "TCC Fuel
         Reconciliation" in Note 5).
o        Decreased revenues from REPs year-to-date consisting of a decrease in
         delivery revenues of $58 million offset in part by an increase of $51
         million for generation revenues. The transition to REPs occurred
         during January and February of 2002, resulting in the variance for
         the year.
o        Income Taxes increased $39 million year-to-date and $15 million for
         the second quarter due to increases in pre-tax operating book income.

Other Impacts on Earnings

Net nonoperating income and expense increased $5 million year-to-date primarily
due to increased gains from risk management activities.

Interest Charges increased $4 million year-to-date and $3 million for the second
quarter primarily due to less capitalized interest due to declines in the amount
of construction work in process in the current year.

Cumulative Effect of Accounting Change

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


Financial Condition
-------------------

Credit Ratings

The rating agencies currently have TCC on stable outlook. Our current ratings
are as follows:

                                             Moody's       S&P         Fitch
                                             -------       ---         -----

          First Mortgage Bonds               Baa1          BBB         A
          Senior Unsecured Debt              Baa2          BBB         A-

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of TCC's rating for unsecured debt from Baa1 to Baa2. 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.

Cash Flow

Cash flows for the six months ended June 30, 2003 and 2002 were as follows:
<TABLE>
<CAPTION>

                                                                2003             2002
                                                               ------          -------
                                                                    (in thousands)
<S>                                                          <C>                <C>
Cash and cash equivalents at beginning of period             $  85,420          $ 10,909
Cash flow from (used for):
  Operating activities                                         178,228           (49,869)
  Investing activities                                         (56,013)          (64,147)
  Financing activities                                        (154,964)          131,492
                                                             ---------         ---------
Net increase (decrease) in cash and cash equivalents           (32,749)           17,476
                                                             ---------         ---------

Cash and cash equivalents at end of period                   $  52,671         $  28,385
                                                             =========         =========
</TABLE>

Operating Activities

Cash flow from operating activities increased $228 million from the prior year
primarily due to a $70 million increase in net income as explained above and
accounts receivables changes related to reduced levels of risk management
activities, offset by the non-cash Texas wholesale clawback recorded in 2003.

Investing Activities

Construction expenditures in 2003 versus 2002 decreased by $8 million. The
current year investment expenditures of $56 million were primarily focused on
improved service reliability projects for transmission and distribution systems.

Financing Activities

Net cash flow used for financing activities increased $286 million for the
current year versus prior year. Prior year funds were used to pay down term debt
and retire common stock, whereas current year proceeds were primarily used to
pay down short-term debt.

Financing Activity

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%. The proceeds from the
bond issuances were used to repay a bank facility, short-term debt, $18 million
of first mortgage bonds due 2023 at 7.50% and for other corporate purposes.
During the first quarter of 2003, TCC retired $16 million of first mortgage
bonds at maturity and $32 million of securitization bonds due 2005. See Note 12
for additional information related to financing activity.

Significant Factors
-------------------

Possible Divestitures

In June 2003, we began actively seeking buyers for 4,497 megawatts of
unregulated generation capacity in Texas to establish a market price for
calculation of stranded cost (see Note 6).

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, cash flows and
financial condition.

Nuclear Plant Outage

In April 2003, engineers at STP, during inspections conducted regularly as part
of scheduled refueling outages, found wall cracks in two bottom mounted
instrument guide tubes of STP Unit 1. These cracks have been repaired and the
unit is expected to return to service in late summer. AEP's share of the direct
cost of repair is approximately $6 million through June 30, 2003. STP officials
are working closely with the NRC to safely return the unit to service. We have
commitments to provide power to customers during the outage. Therefore, we will
be subject to fluctuations in the market prices of electricity and purchased
replacement energy could be a significant cost and could affect our results of
operations and financial position.

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets

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

               Roll-Forward of MTM Risk Management Contract Net Assets
                            Six Months Ended June 30, 2003

 Domestic Power
                                                          (in thousands)
 Beginning Balance December 31, 2002                         $ 5,414
 -----------------------------------
 (Gain) Loss from Contracts  Realized/Settled
  During  the Period (a)                                      (1,883)
 Fair Value of New Contracts When Entered Into
 During the Period (b)                                          -
 Net Option Premiums Paid/(Received) (c)                        -
 Change in Fair Value Due to Valuation
  Methodology  Changes                                          -
 Effect of 98-10 Rescission                                      187
 Changes in Fair Value of Risk Management
  Contracts (d)                                                  (72)
 Changes in Fair Value of Risk Management Contracts
 Allocated to Regulated  Jurisdictions (e)                      -
                                                             -------
 Total MTM Risk Management Contract Net
  Assets                                                       3,646
 Net Non-Trading Related Derivative Contracts                 (1,205)
                                                             -------

 Net Fair Value of Risk Management and Derivative
 Contracts June 30, 2003                                     $ 2,441
                                                             =======

  (a)"(Gain) Loss from Contracts Realized/Settled During the Period"
      includes realized gains from risk management contracts and related
      derivatives that settled during 2003 that were entered into prior
      to 2003.
  (b) The "Fair Value of New Contracts When Entered Into During the
      Period" represents the fair value of long-term contracts entered
      into with customers during 2003. The fair value is calculated as of
      the execution of the contract. Most of the fair value comes from
      longer term fixed price contracts with customers that seek to limit
      their risk against fluctuating energy prices. The contract prices
      are valued against market curves associated with the delivery
      location.
  (c)"Net Option Premiums Paid/(Received)" reflects the net option
      premiums paid/(received) as they relate to unexercised and
      unexpired option contracts that were entered into in 2003.
  (d)"Changes in Fair Value of Risk Management Contracts" represents the
      fair value change in the risk management portfolio due to market
      fluctuations during the current period. Market fluctuations are
      attributable to various factors such as supply/demand, weather,
      etc.
  (e)"Change in Fair Value of Risk Management Contracts Allocated to
      Regulated Jurisdictions" relates to the net gains (losses) of those
      contracts that are not reflected in the Consolidated Statements of
      Income. These net gains (losses) are recorded as regulatory
      liabilities/assets for those subsidiaries that operate in regulated
      jurisdictions.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
 o The source of fair value used in determining the carrying amount of our
   total MTM asset or liability (external sources or modeled internally).
 o The maturity, by year, of our net assets/liabilities, giving an indication
   of when these MTM amounts will settle and generate cash.
<TABLE>
<CAPTION>

                                                Maturity and Source of Fair Value of MTM
                                                   Risk Management Contract Net Assets
                                              Fair Value of Contracts as of June 30, 2003

                                               Remainder                                                        After
                                                 2003         2004         2005        2006         2007         2007       Total
                                                 ----         ----         ----        ----         ----         ----       -----
                                                                                 (in thousands)
<S>                                                <C>        <C>          <C>         <C>          <C>          <C>        <C>
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                           $786       $855         $287        $255         $ 81         $ -        $2,264
Prices Based on Models and Other
 Valuation Methods (b)                               51        113          125         218          220          655        1,382
                                                   ----       ----         ----        ----         ----         ----       ------

    Total                                          $837       $968         $412        $473         $301         $655       $3,646
                                                   ====       ====         ====        ====         ====         ====       ======
</TABLE>

     (a)"Prices Provided by Other External Sources - OTC Broker Quotes" reflects
       information obtained from over-the-counter brokers, industry services, or
       multiple-party on-line platforms.
     (b)"Prices Based on Models and Other Valuation Methods" if there is
       absence of pricing information from external sources, modeled
       information is derived using valuation models developed by the
       reporting entity, reflecting when appropriate,
       option pricing theory, discounted cash flow concepts, valuation
       adjustments, etc. and may require projection of prices for underlying
       commodities beyond the period that prices are available from third-party
       sources. In addition, where external pricing information or market
       liquidity are limited, such valuations are classified as modeled. The
       determination of the point at which a market is no longer liquid for
       placing it in the Modeled category varies by market.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).

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.

                  Total Other Comprehensive Income (Loss) Activity
                          Six Months Ended June 30, 2003

                                                                 Domestic
                                                                   Power
                                                                 --------
                                                              (in thousands)
                 Accumulated OCI, December 31, 2002                $ (36)
                 ----------------------------------
                 Changes in Fair Value (a)                          (767)
                 Reclassifications from OCI to Net
                  Income (b)                                          20
                                                                   -----
                 Accumulated OCI Derivative Gain  (Loss)
                 June 30, 2003                                     $(783)
                                                                   =====

(a)   "Changes in Fair Value" shows changes in the fair value of derivatives
      designated as hedging instruments in cash flow hedges during the
      reporting period not yet reclassified into net income, pending the
      hedged item's affecting net income. Amounts are reported net of related
      income taxes.
(b)   "Reclassifications from OCI to Net Income" represents gains or losses
      from derivatives used as hedging instruments in cash flow hedges that
      were reclassified into net income during the reporting period. Amounts
      are reported net of related income taxes above.

The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $532 thousand loss.

Credit Risk

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

VaR Associated with Energy Trading Contracts

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

                  June 30, 2003                                 December 31, 2002
                  (in thousands)                                  (in thousands)
 End        High       Average      Low               End        High       Average    Low
 ---        ----       -------      ---               ---        ----       -------    ---
<C>         <C>         <C>        <C>               <C>         <C>         <C>       <C>
$109        $742        $413       $109              $115        $353        $126      $26

</TABLE>

<PAGE>
<TABLE>
<CAPTION>



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

                                                                 Three Months Ended June 30,             Six Months Ended June 30,
                                                                2003                2002                 2003              2002
                                                                ----                ----                 ----              ----
                                                                                          (in thousands)
OPERATING REVENUES:
<S>                                                            <C>                  <C>                <C>               <C>
    Electric Generation, Transmission and  Distribution        $409,796             $ 75,139           $ 821,179         $ 195,187
    Sales to AEP Affiliates                                      72,650              285,252              89,625           444,114
                                                               --------             --------            --------         ---------

           TOTAL OPERATING REVENUES                             482,446              360,391             910,804           639,301
                                                               --------             --------           ---------         ---------

OPERATING EXPENSES:
    Fuel for Electric Generation                                 21,430               22,738              48,769            49,727
    Fuel from Affiliates for Electric  Generation                44,911               67,218              83,200            94,557
    Purchased Electricity for Resale                            116,654                5,972             188,776             9,984
    Purchased Electricity from AEP Affiliates                     7,210               12,564              18,772            20,491
    Other Operation                                              70,290               71,975             139,692           137,961
    Maintenance                                                  21,811               14,782              37,910            25,741
    Depreciation and Amortization                                51,860               60,923              95,933           102,770
    Taxes Other Than Income Taxes                                19,783               23,474              42,762            51,396
    Income Taxes                                                 31,894               16,426              66,377            26,910
                                                               --------             --------           ---------         ---------

           TOTAL OPERATING EXPENSES                             385,843              296,072             722,191           519,537
                                                               --------             --------           ---------         ---------

OPERATING INCOME                                                 96,603               64,319             188,613           119,764

NONOPERATING INCOME                                               7,901                4,472              18,063            14,003

NONOPERATING EXPENSES                                             5,637                3,478              10,832            12,865

NONOPERATING INCOME TAX EXPENSE (CREDIT)                            240                 (648)                798              (515)

INTEREST CHARGES                                                 35,040               32,426              67,022            63,437
                                                               --------             --------           ---------         ---------

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE             63,587               33,535             128,024            57,980

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

NET INCOME                                                       63,587               33,535             128,146            57,980

PREFERRED STOCK DIVIDEND  REQUIREMENTS                               61                   61                 121               121
                                                               --------             --------           ---------         ---------

EARNINGS APPLICABLE TO COMMON  STOCK                           $ 63,526             $ 33,474           $ 128,025         $  57,859
                                                               ========             ========           =========         =========
</TABLE>

The common stock of TCC is owned by a wholly owned subsidiary of AEP

See Notes to Respective Financial Statements beginning on page L-1.
<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                                                                    (77,004)                         (77,004)
Preferred Stock Dividends                                                                    (121)                            (121)
                                                                                                                        ----------
                                                                                                                           936,970
                                                                                                                        ----------
Comprehensive Income:
  Other Comprehensive Income                                                                                 263               263
  Net Income                                                                               57,980                           57,980
                                                                                                                        ----------
     Total Comprehensive Income                                                                                             58,243
                                                      --------       --------           ---------        -------        ----------

JUNE 30, 2002                                         $ 55,292       $132,606           $ 807,052        $   263        $  995,213
                                                      ========       ========           =========        =======        ==========



JANUARY 1, 2003                                       $ 55,292       $132,606           $ 986,396        $(73,160)      $1,101,134
Common Stock Dividends                                                                    (60,401)                         (60,401)
Preferred Stock Dividends                                                                    (121)                            (121)
                                                                                                                        ----------
                                                                                                                         1,040,612
                                                                                                                        ----------
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                           (747)            (747)
  Net Income                                                                              128,146                          128,146
                                                                                                                        ----------
     Total Comprehensive Income                                                                                            127,399
                                                      --------       --------          ----------        --------       ----------

JUNE 30, 2003                                         $ 55,292       $132,606          $1,054,020        $(73,907)      $1,168,011
                                                      ========       ========          ==========        ========       ==========
</TABLE>

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



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


                                                                                              June 30, 2003      December 31, 2002
                                                                                              -------------      -----------------
                                                                                                         (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                             <C>                     <C>
  Production                                                                                    $ 3,001,126             $2,903,942
  Transmission                                                                                      757,405                698,964
  Distribution                                                                                    1,336,867              1,296,731
  General                                                                                           261,065                258,386
  Construction Work in Progress                                                                      82,170                200,947
  Nuclear Fuel                                                                                      270,570                266,766
                                                                                                 ----------             ----------
          Total Electric Utility Plant                                                            5,709,203              5,625,736
  Accumulated Depreciation and Amortization                                                       2,359,185              2,405,492
                                                                                                 ----------             ----------
          NET ELECTRIC UTILITY PLANT                                                              3,350,018              3,220,244
                                                                                                 ----------             ----------

OTHER PROPERTY AND INVESTMENTS                                                                        3,991                  3,977
                                                                                                 ----------             ----------

SECURITIZED TRANSITION ASSETS                                                                       716,404                734,591
                                                                                                 ----------             ----------

LONG-TERM RISK MANAGEMENT ASSETS                                                                     16,382                  4,392
                                                                                                -----------             ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                          52,671                 85,420
  Advances to/from Affiliates, net                                                                   51,501                    -
  Accounts Receivable:
    General                                                                                         220,864                113,543
    Affiliated Companies                                                                             86,329                121,324
    Allowance for Uncollectible Accounts                                                               (256)                  (346)
  Fuel Inventory                                                                                     20,475                 32,563
  Materials and Supplies                                                                             47,225                 51,593
  Accrued Utility Revenues                                                                           42,425                 27,150
  Risk Management Assets                                                                             25,983                 22,493
  Prepayments and Other Current Assets                                                                3,670                  2,133
                                                                                                 ----------             ----------
          TOTAL CURRENT ASSETS                                                                      550,887                455,873
                                                                                                 ----------             ----------

REGULATORY ASSETS                                                                                   608,119                458,552
                                                                                                 ----------             ----------

REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION                                       320,895                336,444
                                                                                                 ----------             ----------

NUCLEAR DECOMMISSIONING TRUST FUND                                                                  108,547                 98,474
                                                                                                 ----------             ----------

DEFERRED CHARGES                                                                                     74,085                 43,891
                                                                                                 ----------             ----------

                    TOTAL ASSETS                                                                 $5,749,328             $5,356,438
                                                                                                 ==========             ==========
</TABLE>

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


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


                                                                                            June 30, 2003        December 31, 2002
                                                                                            -------------        -----------------
                                                                                                      (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $25 Par Value:
    Authorized - 12,000,000 Shares
<S>                                                                                              <C>                 <C>
    Outstanding - 2,211,678 Shares                                                               $   55,292          $   55,292
  Paid-in Capital                                                                                   132,606             132,606
  Accumulated Other Comprehensive Income (Loss)                                                     (73,907)            (73,160)
  Retained Earnings                                                                               1,054,020             986,396
                                                                                                 ----------          ----------
    Total Common Shareholder's Equity                                                             1,168,011           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                                                                                  1,962,660           1,209,434
                                                                                                 ----------          ----------
          TOTAL CAPITALIZATION                                                                    3,272,863           2,452,760
                                                                                                 ----------          ----------

OTHER NONCURRENT LIABILITIES                                                                        324,637              74,572
                                                                                                 ----------          ----------

CURRENT LIABILITIES:
  Short-term Debt - Affiliates                                                                         -                650,000
  Long-term Debt Due Within One Year                                                                209,705             229,131
  Advances to/from Affiliates, net                                                                     -                126,711
  Accounts Payable - General                                                                        113,437              72,199
  Accounts Payable - Affiliated Companies                                                            78,974              36,242
  Customer Deposits                                                                                   2,271                 666
  Taxes Accrued                                                                                      73,068              24,791
  Interest Accrued                                                                                   43,595              51,205
  Risk Management Liabilities                                                                        33,776              19,811
  Other                                                                                              19,191              36,698
                                                                                                 ----------          ----------

          TOTAL CURRENT LIABILITIES                                                                 574,017           1,247,454
                                                                                                 ----------          ----------

DEFERRED INCOME TAXES                                                                             1,256,646           1,261,252
                                                                                                 ----------          ----------

DEFERRED INVESTMENT TAX CREDITS                                                                     115,082             117,686
                                                                                                 ----------          ----------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                                 6,148               1,713
                                                                                                 ----------          ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                         199,935             201,001
                                                                                                 ----------          ----------

COMMITMENTS AND CONTINGENCIES (Note 7)

                    TOTAL CAPITALIZATION AND LIABILITIES                                         $5,749,328          $5,356,438
                                                                                                 ==========          ==========
</TABLE>

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


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

                                                                                                 Six Months Ended June 30,
                                                                                                2003                  2002
                                                                                                ----                  ----
                                                                                                      (in thousands)
OPERATING ACTIVITIES:
<S>                                                                                           <C>                   <C>
   Net Income                                                                                 $ 128,146             $  57,980
   Adjustments to Reconcile Net Income to Net Cash Flows
    From (Used For) Operating Activities:
      Depreciation and Amortization                                                              95,933               102,770
      Deferred Income Taxes                                                                      13,369               (18,103)
      Deferred Investment Tax Credits                                                            (2,603)               (2,603)
      Cumulative Effect of Accounting Change                                                       (122)                 -
      Mark-to-Market of Risk Management Contracts                                                 1,955                 3,932
      Texas Wholesale Clawback                                                                 (108,400)                 -
   Changes in Certain Assets and Liabilities:
      Accounts Receivable, net                                                                  (72,416)             (270,791)
      Fuel, Materials and Supplies                                                               16,456                (1,071)
      Interest Accrued                                                                           (7,610)                6,107
      Accrued Utility Revenues                                                                  (15,275)                 -
      Accounts Payable                                                                           83,970               106,693
      Taxes Accrued                                                                              48,277                25,651
      Deferred Property Tax                                                                     (20,100)              (19,120)
   Change in Other Assets                                                                         8,433               (38,746)
   Change in Other Liabilities                                                                    8,215                (2,568)
                                                                                              ---------             ---------
           Net Cash Flows From (Used For) Operating Activities                                  178,228               (49,869)
                                                                                              ---------             ---------

INVESTING ACTIVITIES:
   Construction Expenditures                                                                    (56,013)              (64,147)
   Other                                                                                           -                     -
                                                                                              ---------             ---------
           Net Cash Flows Used For Investing Activities                                         (56,013)              (64,147)
                                                                                              ---------             ---------

FINANCING ACTIVITIES:
   Change in Short-term Debt-Affiliates                                                        (650,000)              200,000
   Issuance of Long-term Debt                                                                   800,000               796,613
   Retirement of Long-term Debt                                                                 (66,230)             (150,000)
   Change in Advances to/from Affiliates, net                                                  (178,212)             (251,992)
   Retirement of Common Stock                                                                      -                 (386,004)
   Dividends Paid on Common Stock                                                               (60,401)              (77,004)
   Dividends Paid on Cumulative Preferred Stock                                                    (121)                 (121)
                                                                                              ---------             ---------
           Net Cash Flows From (Used For) Financing Activities                                 (154,964)              131,492
                                                                                              ---------             ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                            (32,749)               17,476
Cash and Cash Equivalents at Beginning of Period                                                 85,420                10,909
                                                                                              ---------             ---------
Cash and Cash Equivalents at End of Period                                                    $  52,671             $  28,385
                                                                                              =========             =========
</TABLE>

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $72,918,000 and
$40,588,000 and for income taxes was $7,803,000 and $44,322,000 in 2003 and
2002, respectively.

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

<PAGE>

                             AEP TEXAS NORTH COMPANY
              MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations
---------------------

Net Income increased $23 million year-to-date and $17 million for the second
quarter primarily due to Reliability Must Run (RMR) margins from ERCOT (see
"Texas Plants" in Note 13 in the Annual Report, as updated by the Current Report
on Form 8-K dated May 14, 2003, for discussion of RMR facilities) and increased
revenues from generation sales, mostly to REPs in Texas.

Since REPs are the electricity suppliers to retail customers in the ERCOT area,
we sell our generation to the REPs and other market participants and provide
transmission and distribution services to retail customers of the REPs in our
service territory. As a result of the provision of retail electric service by
REPs effective January 1, 2002, we no longer supply electricity directly to
retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in our sales as further described below.

In December 2002, AEP sold Mutual Energy WTU to an unrelated third party, who
assumed the obligations of the affiliated REP, including the provision of
price-to-beat rates under the Texas Restructuring Legislation. Prior to the
sale, during 2002, sales to Mutual Energy WTU were classified as Sales to AEP
Affiliates. Subsequent to the sale, energy transactions with Mutual Energy WTU
are classified as Electric Generation and delivery charges as Electric
Transmission and Distribution.

Operating Income

Operating Income increased by $17 million year-to-date and $18 million for the
second quarter primarily due to the following:

o   RMR stand-by  revenues from ERCOT of $7 million year-to-date and $4
    million for the second quarter.
o   Increased revenues from ERCOT for scheduling and balancing services of $13
    million year-to-date and $3 million for the second quarter.
o   Reduction in provision for rate refunds in the second quarter of $3
    million.
o   Reduced Other Operation and Maintenance expenses of $7 million year-to-date
    and $4 million for the second quarter resulting from the Sustained
    Earnings Improvement program, reduced expenses for employee benefits due to
    revaluations, and reduced AEPSC billings for customer-related charges.
o   Reduced Depreciation and Amortization of $3 million year-to-date and $1
    million for the second quarter mainly from the mothballing of several
    plants in late 2002.
o   Reduced Taxes Other Than Income Taxes of $3 million year-to-date and
    $2 million for the second quarter due mainly to declines in gross receipts
    and property taxes due in large part to the taxable revaluation of plants.

The increase in Operating Income was partially offset by:

o   Increased Income Tax Expense (Credit) of $12 million for the year-to-date
    and $10 million for the second quarter due to increases in pre-tax
    operating book income.
o   Increased provision for rate refunds for the year-to-date of $9 million
    (see "TNC Fuel Reconciliation" in Note 5).
o   Increased fuel and purchased power expenses of $30 million year-to-date
    and $12 million for the second quarter due mainly to higher prices
    resulting from increased natural gas prices. KWH generation decreased
    due to the mothballing of several plants in late 2002 and KWH purchases
    increased to compensate for the mothballing of plants.

Other Impacts on Earnings

Net nonoperating income and expense increased $3 million year-to-date primarily
due to a $1 million increase in income from significantly higher levels of line
construction work for others and a $4 million increase in income from risk
management activities.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 (see Note 3).

Financial Condition
-------------------

Credit Ratings

The rating agencies currently have TNC on stable outlook. Our current ratings
are as follows:

                                             Moody's       S&P         Fitch
                                             -------       ---         -----
          First Mortgage Bonds               A3            BBB         A
          Senior Unsecured Debt              Baa1          BBB         A-

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. TNC had its mortgage bond debt downgraded from
A2 to A3. The completion of this review was a culmination of ratings action
started during 2002. In March 2003, S&P lowered AEP and its subsidiaries senior
unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP
subsidiaries.

Financing Activities

We issued $225 million of unsecured senior notes due 2013 at a coupon of 5.50%.
The proceeds from the bond issuance were used to repay an April 2003 bank
facility, short-term debt and other corporate purposes. See Note 12 for
additional information related to financing activity.

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.


Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets

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


<PAGE>



             Roll-Forward of MTM Risk Management Contract Net Assets
                         Six Months Ended June 30, 2003

        Domestic Power
        --------------
                                                             (in thousands)
        Beginning Balance December 31, 2002                      $2,043
        -----------------------------------
        (Gain) Loss from Contracts Realized/Settled
         During the Period (a)                                     (160)
        Fair Value of New Contracts When Entered  Into
        During the Period (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 (d)                                            2,392
        Changes in Fair Value of Risk Management Contracts
        Allocated to Regulated Jurisdictions (e)                    673
                                                                 ------
        Total MTM Risk Management Contract Net
         Assets                                                   4,968
        Net Non-Trading Related Derivative
         Contracts                                                 (499)
                                                                 ------
        Net Fair Value of Risk Management and  Derivative
        Contracts June 30, 2003                                  $4,469
                                                                 ======


        (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)"Changes in Fair Value of Risk Management Contracts" represents the
            fair value change in the risk management portfolio due to market
            fluctuations during the current period. Market fluctuations are
            attributable to various factors such as supply/demand, weather, etc.
        (e)"Change in Fair Value of Risk Management Contracts Allocated to
            Regulated Jurisdictions" relates to the net gains (losses) of those
            contracts that are not reflected in the Consolidated Statements of
            Income. These net gains (losses) are recorded as regulatory
            liabilities/assets for those subsidiaries that operate in regulated
            jurisdictions.


Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
 o The source of fair value used in determining the carrying amount of our
   total MTM asset or liability (external sources or modeled internally).
 o The maturity, by year, of our net assets/liabilities, giving an indication
   of when these MTM amounts will settle and generate cash.
<TABLE>
<CAPTION>


                                                     Maturity and Source of Fair Value of MTM
                                                        Risk Management Contract Net Assets
                                                    Fair Value of Contracts as of June 30, 2003

                                               Remainder                                                      After
                                                  2003         2004      2005        2006         2007        2007        Total
                                                  ----         ----      ----        ----         ----        ----        ------
                                                                                (in thousands)
<S>                                                <C>         <C>       <C>         <C>          <C>          <C>        <C>
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                           $1,073      $1,165    $391        $347          $111        $ -        $3,087
Prices Based on Models and Other
 Valuation Methods (b)                                 69         153     171         296           300         892        1,881
                                                   ------      ------    ----        ----          ----        ----       ------

    Total                                          $1,142      $1,318    $562        $643          $411        $892       $4,968
                                                   ======      ======    ====        ====          ====        ====       ======
</TABLE>

     (a) "Prices Provided by Other External Sources - OTC Broker Quotes"
         reflects information obtained from over-the-counter brokers, industry
         services, or multiple-party on-line platforms.
     (b) "Prices Based on Models and Other Valuation Methods" if there is
         absence of pricing information from external sources, modeled
         information is derived using valuation models developed by the
         reporting entity, reflecting when appropriate, option pricing theory,
         discounted cash flow concepts, valuation adjustments, etc. and may
         require projection of prices for underlying commodities beyond the
         period that prices are available from third-party sources. In addition,
         where external pricing information or market liquidity are limited,
         such valuations are classified as modeled. The determination of the
         point at which a market is no longer liquid for placing it in the
         Modeled category varies by market.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).

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.

                Total Other Comprehensive Income (Loss) Activity
                         Six Months Ended June 30, 2003

                                                       Domestic
                                                        Power
                                                        -----
                                                   (in thousands)
        Accumulated OCI, December 31, 2002                $  (15)
        ----------------------------------
        Changes in Fair Value (a)                           (317)
        Reclassifications from OCI to Net
         Income (b)                                            8
                                                          ------
        Accumulated OCI Derivative Gain  (Loss)
        June 30, 2003                                     $ (324)
                                                          ======

(a)      "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
(b)      "Reclassifications from OCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.


The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $220 thousand loss.

Credit Risk

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

VaR Associated with Energy Trading Contracts

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

                June 30, 2003                               December 31, 2002
                (in thousands)                               (in thousands)
End        High       Average      Low          End        High       Average    Low
---        ----       -------      ---          ---        ----       -------    ---
<C>        <C>          <C>        <C>          <C>        <C>          <C>      <C>
$45        $307         $171       $45          $48        $146         $52      $11

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


                                                          AEP TEXAS NORTH COMPANY
                                                            STATEMENTS OF INCOME
                                                                (UNAUDITED)

                                                                    Three Months Ended June 30,      Six Months Ended June 30,
                                                                  2003                 2002               2003               2002
                                                                  ----                 ----               ----               ----
                                                                                           (in thousands)
OPERATING REVENUES:
<S>                                                             <C>                  <C>                <C>               <C>
   Electric Generation, Transmission and  Distribution          $103,136             $ 40,225           $216,629          $ 93,334
   Sales to AEP Affiliates                                        33,670               64,227             36,439           114,744
                                                                --------             --------           --------          --------
           TOTAL OPERATING REVENUES                              136,806              104,452            253,068           208,078
                                                                --------             --------           --------          --------

OPERATING EXPENSES:
   Fuel for Electric Generation                                    8,278                9,299             19,739            18,013
   Fuel from Affiliates for Electric Generation                   10,917               23,543             17,002            39,809
   Purchased Electricity for Resale                               26,723                7,415             51,501            13,928
   Purchased Electricity from AEP  Affiliates                     16,449               10,559             35,794            22,209
   Other Operation                                                22,365               24,907             42,984            49,077
   Maintenance                                                     6,012                7,050             10,153            11,406
   Depreciation and Amortization                                   9,723               11,072             19,255            22,641
   Taxes Other Than Income Taxes                                   3,432                5,726              9,465            12,026
   Income Tax Expense (Credit)                                     9,664                 (468)            14,067             2,475
                                                                --------             --------           --------          --------
           TOTAL OPERATING EXPENSES                              113,563               99,103            219,960           191,584
                                                                --------             --------           --------          --------

OPERATING INCOME                                                  23,243                5,349             33,108            16,494

NONOPERATING INCOME                                               17,833                6,980             31,296             5,492

NONOPERATING EXPENSES                                             17,113                5,688             28,672             7,060

NONOPERATING INCOME TAX EXPENSE (CREDIT)                             142                  358                481              (631)

INTEREST CHARGES                                                   5,899                5,608             10,564            10,890
                                                                --------             --------           --------          --------

INCOME BEFORE CUMULATIVE EFFECT  OF ACCOUNTING CHANGES            17,922                  675             24,687             4,667

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

NET INCOME                                                        17,922                  675             27,758             4,667

PREFERRED STOCK DIVIDEND  REQUIREMENTS                                26                   26                 52                52
                                                                --------             --------           --------          --------

EARNINGS APPLICABLE TO COMMON  STOCK                            $ 17,896             $    649           $ 27,706          $  4,615
                                                                ========             ========           ========          ========
</TABLE>

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

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

<TABLE>
<CAPTION>



                                                       AEP TEXAS NORTH COMPANY
                              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>              <C>
JANUARY 1, 2002                                     $137,214         $2,351            $105,970         $  -            $245,535
Common Stock Dividends                                                                  (13,498)                         (13,498)
Preferred Stock Dividends                                                                   (52)                             (52)
                                                                                                                        --------
                                                                                                                         231,985
                                                                                                                        --------
Comprehensive Income:
  Other Comprehensive Income, Net of Taxes:
   Unrealized Gain on Cash Flow Power Hedges                                                                 78               78
  Net Income                                                                              4,667                            4,667
                                                                                                                        --------
     Total Comprehensive Income                                                                                            4,745
                                                    --------         ------            --------         -------         --------

JUNE 30, 2002                                       $137,214         $2,351            $ 97,087         $    78         $236,730
                                                    ========         ======            ========         =======         ========



JANUARY 1, 2003                                     $137,214         $2,351            $ 71,942        $(30,763)        $180,744
Common Stock Dividends                                                                   (4,970)                          (4,970)
Preferred Stock Dividends                                                                   (52)                             (52)
                                                                                                                        --------
                                                                                                                         175,722
                                                                                                                        --------
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                         (309)            (309)
    Unrealized Loss on Minimum
      Pension Liability                                                                                      (7)              (7)
  Net Income                                                                             27,758                           27,758
                                                                                                                        --------
     Total Comprehensive Income                                                                                           27,442
                                                    --------         ------            --------        --------         --------

JUNE 30, 2003                                       $137,214         $2,351            $ 94,678        $(31,079)        $203,164
                                                    ========         ======            ========        ========         ========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                                  AEP TEXAS NORTH COMPANY
                                                                       BALANCE SHEETS
                                                                        (UNAUDITED)

                                                                                             June 30, 2003       December 31, 2002
                                                                                             -------------       -----------------
                                                                                                       (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                           <C>                      <C>
   Production                                                                                 $  356,889               $  353,087
   Transmission                                                                                  256,304                  254,483
   Distribution                                                                                  447,789                  445,486
   General                                                                                       109,892                  111,679
   Construction Work in Progress                                                                  42,187                   37,012
                                                                                              ----------               ----------
        Total Electric Utility Plant                                                           1,213,061                1,201,747
   Accumulated Depreciation and Amortization                                                     524,323                  521,792
                                                                                              ----------               ----------
       NET ELECTRIC UTILITY PLANT                                                                688,738                  679,955
                                                                                              ----------               ----------

OTHER PROPERTY AND INVESTMENTS                                                                     1,203                    1,213
                                                                                              ----------               ----------

LONG-TERM RISK MANAGEMENT ASSETS                                                                   6,637                    2,248
                                                                                              ----------               ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                       2,952                    1,219
   Advances to Affiliates                                                                         11,905                     -
   Accounts Receivable:
      Customers                                                                                   55,213                   62,660
      Affiliated Companies                                                                        25,505                   43,632
      Allowance for Uncollectible Accounts                                                        (4,746)                  (5,041)
   Fuel Inventory                                                                                  8,598                   12,677
   Materials and Supplies                                                                          9,345                    9,574
   Accrued Utility Revenues                                                                        7,425                    6,829
   Risk Management Assets                                                                          6,237                    4,130
   Prepayments and Other                                                                             966                    1,070
                                                                                              ----------               ----------
          TOTAL CURRENT ASSETS                                                                   123,400                  136,750
                                                                                              ----------               ----------

REGULATORY ASSETS                                                                                 43,477                   45,097
                                                                                              ----------               ----------

DEFERRED CHARGES                                                                                  25,440                   11,912
                                                                                              ----------               ----------

          TOTAL ASSETS                                                                        $  888,895               $  877,175
                                                                                              ==========               ==========
</TABLE>

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


                                                           AEP TEXAS NORTH COMPANY
                                                                BALANCE SHEETS
                                                                 (UNAUDITED)

                                                                                      June 30, 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)                                           (31,079)                    (30,763)
   Retained Earnings                                                                        94,678                      71,942
                                                                                          --------                    --------
        Total Common Shareholder's Equity                                                  203,164                     180,744
Cumulative Preferred Stock Not Subject to
  Mandatory Redemption                                                                       2,367                       2,367
Long-term Debt                                                                             333,486                     132,500
                                                                                          --------                    --------

        TOTAL CAPITALIZATION                                                               539,017                     315,611
                                                                                          --------                    --------

OTHER NONCURRENT LIABILITIES                                                                41,079                      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                                                               19,670                      32,714
   Accounts Payable - Affiliated Companies                                                  27,276                      76,217
   Customer Deposits                                                                           453                         117
   Taxes Accrued                                                                            19,831                       3,697
   Interest Accrued                                                                          6,610                       2,776
   Risk Management Liabilities                                                               5,969                       3,801
   Other                                                                                    12,463                      17,414
                                                                                          --------                    --------

        TOTAL CURRENT LIABILITIES                                                          116,308                     342,143
                                                                                          --------                    --------

DEFERRED INCOME TAXES                                                                      118,113                     117,521
                                                                                          --------                    --------

DEFERRED INVESTMENT TAX CREDITS                                                             20,750                      21,510
                                                                                          --------                    --------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                        2,436                         557
                                                                                          --------                    --------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                 51,192                      50,972
                                                                                          --------                    --------

COMMITMENTS AND CONTINGENCIES (Note 7)

        TOTAL CAPITALIZATION AND LIABILITIES                                              $888,895                    $877,175
                                                                                          ========                    ========
</TABLE>

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



<PAGE>
<TABLE>
<CAPTION>



                                                       AEP TEXAS NORTH COMPANY
                                                       STATEMENTS OF CASH FLOWS
                                                             (UNAUDITED)

                                                                                            Six Months Ended June 30,
                                                                                            2003                  2002
                                                                                            ----                  ----
                                                                                                  (in thousands)
OPERATING ACTIVITIES:
<S>                                                                                      <C>                    <C>
 Net Income                                                                              $ 27,758               $  4,667
   Adjustments to Reconcile Net Income to Net Cash Flows
     From (Used For) Operating Activities:
    Depreciation and Amortization                                                          19,255                 22,641
    Deferred Income Taxes                                                                  (1,079)                 1,470
    Deferred Investment Tax Credits                                                          (760)                  (636)
    Cumulative Effect of Accounting Changes                                                (3,071)                  -
    Mark-to-Market of Risk Management Contracts                                            (2,905)                (1,134)
 Changes in Certain Assets and Liabilities:
      Accounts Receivable, net                                                             25,279                (74,776)
      Fuel, Materials and Supplies                                                          4,308                  4,995
      Accrued Utility Revenues                                                               (596)                  -
      Accounts Payable                                                                    (61,985)                37,983
      Taxes Accrued                                                                        16,134                  1,145
      Fuel Recovery                                                                          -                    (2,051)
      Deferred Property Taxes                                                              (6,645)                (7,175)
 Change in Other Assets                                                                    (7,657)               (16,944)
 Change in Other Liabilities                                                               12,045                 (2,018)
                                                                                        ---------              ---------
           Net Cash Flows From (Used For) Operating Activities                             20,081                (31,833)
                                                                                        ---------              ---------

INVESTING ACTIVITIES:
  Construction Expenditures                                                               (21,609)               (25,154)
  Other                                                                                       595                   -
                                                                                        ---------              ---------
           Net Cash Flows Used For Investing Activities                                   (21,014)               (25,154)
                                                                                        ---------              ---------

FINANCING ACTIVITIES:
  Change in Short-term Debt-Affiliates                                                   (125,000)                  -
  Issuance of Long-term Debt                                                              225,000                   -
  Change in Advances to/from Affiliates, net                                              (92,312)                69,991
  Dividends Paid on Common Stock                                                           (4,970)               (13,498)
  Dividends Paid on Cumulative Preferred Stock                                                (52)                   (52)
                                                                                         --------              ---------
           Net Cash Flows From Financing Activities                                         2,666                 56,441
                                                                                        ---------              ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                        1,733                   (546)
Cash and Cash Equivalents at Beginning of Period                                            1,219                  2,454
                                                                                         --------              ---------
Cash and Cash Equivalents at End of Period                                               $  2,952              $   1,908
                                                                                         ========              =========
</TABLE>

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $5,525,000 and
$9,481,000 and for income taxes was $(1,305,000) and $2,408,000 in 2003 and
2002, respectively.

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



<PAGE>
                  APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income for the first half of 2003 increased $69 million over the prior year
period primarily due to the Cumulative Effect of Accounting Changes of $77
million recorded in the first quarter of 2003 and improved margins on higher
overall sales. These increases were partially offset by a $25 million decrease
in Nonoperating Income primarily due to reduced gains from risk management
activities.

Net Income for the second quarter of 2003 decreased $32 million primarily due to
a $15 million increase in capacity charges included in Purchased Electricity
from AEP Affiliates and a $15 million decrease in Nonoperating Income primarily
due to reduced gains from risk management activities. 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. We, as a member of the AEP Power
Pool, share in the revenues and costs of marketing and activities conducted on
our behalf by the AEP Power Pool. Our relative share of the AEP Power Pool
revenues and expenses increased over the prior periods as a result of our
reaching a new peak demand in January 2003, which increased our allocation
factor.

Operating Income

Operating Income for the second quarter of 2003 decreased by $16 million from
2002 primarily due to the following:

o   An increase in Purchased  Electricity from AEP Affiliates of $25 million
    reflecting the increased  capacity  charges  described above and the
    increase in our relative share of the AEP Power Pool expenses.
o   An increase in Maintenance expenses comprised of an increase in
    power plant maintenance at the Amos and Sporn plants for repairs,
    combined with an increase in distribution line maintenance due to
    severe storm damage, for a combined maintenance increase of $9
    million.
o   A decline in retail revenues of $12 million primarily due to
    decreased residential sales reflecting the mild weather in the
    second quarter of 2003 and decreased industrial sales reflecting
    the continued sluggish economy. Cooling degree-days for the
    quarter decreased 52% from the prior period.

The decrease in Operating Income for the second quarter of 2003 was partially
offset by:

o   Higher non-affiliated system sales and Sales to AEP Affiliates
    reflecting an increase in the volume of AEP Power Pool
    transactions, as well as our relative share based on the higher
    allocation factor.
o   A decrease in income taxes of $11 million primarily due to the decrease in
    pre-tax operating book income.

Operating Income for the first half of 2003 increased $15 million primarily due
to the following:

o   AEP Power Pool sales volume increased over 2002, as well as our relative
    share based on the higher allocation factor.  In addition, our residential
    MWH increased 8% year-to-date primarily due to the severe winter weather
    in the first quarter of 2003.
o   A decrease in Depreciation and Amortization expense of $12 million
    due primarily to the adoption of SFAS 143 (see Note 2). Additionally,
    we have 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 for the West Virginia jurisdiction
    in the first quarter of 2003.

The increase in Operating Income for the first half of 2003 was partially offset
by:

o   An increase of $45 million in power costs primarily due to a year-over-year
    increase of $23 million in capacity charges and the increase in our
    relative share of AEP Power Pool expenses.
o   An increase in Maintenance expense of $16 million, due primarily to
    increased  maintenance at Amos and Sporn plants and maintenance of
    overhead lines required due to the severe storm damage in 2003.

Other Impacts on Earnings

Nonoperating Income decreased $15 million and $25 million for the quarter and
six months ended June 30, 2003, respectively, primarily due to a decrease in
gains from risk management activities. The decreases in Nonoperating Income Tax
Expense for both periods were a result of the decreases in Nonoperating Income.

Interest Charges increased $6 million and $8 million for the quarter and six
months ended June 30, 2003, respectively, primarily due to the effects of the
refinancing activities. (See Financing Activities).

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to the implementation of SFAS
143 and EITF 02-03 (see Notes 2 and 3).

Financial Condition
-------------------

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as
follows:
                                             Moody's       S&P         Fitch
                                             -------       ---         -----
          First Mortgage Bonds               Baa1          BBB         A-
          Senior Unsecured Debt              Baa2          BBB         BBB+

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of our rating for unsecured debt from Baa1 to Baa2. The completion of this
review was a culmination of ratings action started during 2002. In March 2003,
S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB
along with the first mortgage bonds of AEP subsidiaries.

Cash Flow

Cash flows for six months ended June 30, 2003 and 2002 were as follows:
<TABLE>
<CAPTION>

                                                                            2003                    2002
                                                                            ----                    ----
                                                                                    (in thousands)
           <S>                                                           <C>                        <C>
           Cash and cash equivalents at beginning of period              $   4,285                  $ 13,663
           Cash flow from (used for):
             Operating activities                                          262,505                   121,804
             Investing activities                                         (113,158)                 (128,270)
             Financing activities                                         (142,962)                   (5,893)
                                                                         ---------                  ---------
           Net increase (decrease) in cash and cash equivalents              6,385                   (12,359)
                                                                         ---------                  ---------

           Cash and cash equivalents at end of period                    $  10,670                  $  1,304
                                                                         =========                  ========
</TABLE>

Operating Activities

Cash flow from operating activities increased $141 million primarily due to
increases in various accounts receivable balances in the six months ended June
30, 2003.

Investing Activities

Construction expenditures in 2003 versus 2002 decreased $14 million. The current
year expenditures of $115 million were focused on improved service reliability
for transmission and distribution, as well as environmental upgrades.


Financing Activities

During the first half of 2003, we had greater net retirements of long-term debt
and advances to affiliates over last year.

Financing Activity

In 2003, we redeemed the following bonds:

           Coupon
          Or Stated            Call                               Principal
            Rate               Rate           Due Date             Amounts
            -----              ----           --------             -------
              %                 %                               (in millions)
              -                 -
             8.50              100              2022                   $70
             7.15              100              2023                    20
             7.80              103.90           2023                    30
             7.20              100              2038                   100
             7.30              100              2038                   100

See Note 12 for additional information related to financing activity.

Significant Factors
-------------------

Federal EPA Complaint and Notice of Violation

As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", APCo and certain affiliated companies 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 and certain
affiliated companies 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 we do not prevail, any capital and operating costs of
additional pollution control equipment that may be required as well as any
penalties imposed would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity. See Note 7 for
further discussion.

NOx Reductions

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.

We are 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 of approximately $462 million. 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).

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets

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

                     Roll-Forward of MTM Risk Management Contract Net Assets
                                  Six Months Ended June 30, 2003

        Domestic Power
        --------------
                                                                (in thousands)

        Beginning Balance December 31, 2002                       $  96,852
        -----------------------------------
        (Gain) Loss from Contracts  Realized/Settled
         During the Period (a)                                     (39,981)
        Fair Value of New Contracts When Entered  Into
         During the Period (b)                                        -
        Net Option Premiums Paid/(Received) (c)                        474
        Change in Fair Value Due to Valuation
         Methodology  Changes                                         -
        Effect of 98-10 Rescission                                  (4,664)
        Changes in Fair Value of Risk Management
         Contracts (d)                                              16,072
        Changes in Fair Value Risk Management Contracts
        Allocated to Regulated Jurisdictions (e)                     4,002
                                                                  --------
        Total MTM Risk Management Contract Net
          Assets                                                    72,755
        Net Non-Trading Related Derivative
          Contracts                                                 (3,594)
                                                                  --------

        Net Fair Value of Risk Management and Derivative
        Contracts June 30, 2003                                   $ 69,161
                                                                  ========

        (a)"(Gain) Loss from Contracts Realized/Settled During the Period"
            includes realized gains from risk management contracts and related
            derivatives that settled during 2003 that were entered into prior to
            2003.
        (b) The "Fair Value of New Contracts When Entered Into During the
            Period" represents the fair value of long-term contracts entered
            into with customers during 2003. The fair value is calculated as of
            the execution of the contract. Most of the fair value comes from
            longer term fixed price contracts with customers that seek to limit
            their risk against fluctuating energy prices. The contract prices
            are valued against market curves associated with the delivery
            location.
        (c) "Net Option Premiums Paid/(Received)" reflects the net option
            premiums paid/(received) as they relate to unexercised and unexpired
            option contracts that were entered into in 2003.
        (d)"Changes in Fair Value of Risk Management Contracts" represents the
            fair value change in the risk management portfolio due to market
            fluctuations during the current period. Market fluctuations are
            attributable to various factors such as supply/demand, weather, etc.
        (e)"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.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
 o The source of fair value used in determining the carrying amount of our
   total MTM asset or liability (external sources or modeled internally).
 o The maturity, by year, of our net assets/liabilities, giving an indication
   of when these MTM amounts will settle and generate cash.
<TABLE>
<CAPTION>

                                               Maturity and Source of Fair Value of MTM
                                                 Risk Management Contract Net Assets
                                              Fair Value of Contracts as of June 30, 2003

                                                Remainder                                                     After
                                                  2003        2004       2005        2006         2007         2007       Total
                                                  ----        ----       ----        ----         ----         ----       -----
                                                                                 (in thousands)
<S>                                              <C>         <C>        <C>         <C>          <C>          <C>        <C>
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                         $15,531     $17,672    $5,666      $5,025       $1,605       $  -       $45,499
Prices Based on Models and Other
 Valuation Methods (b)                             1,006       2,223     2,474       4,293        4,340        12,920     27,256
                                                 -------     -------    ------      ------       ------       -------    -------

    Total                                        $16,537     $19,895    $8,140      $9,318       $5,945       $12,920    $72,755
                                                 =======     =======    ======      ======       ======       =======    =======
</TABLE>

     (a) "Prices Provided by Other External Sources - OTC Broker Quotes"
         reflects information obtained from over-the-counter brokers, industry
         services, or multiple-party on-line platforms.
     (b) "Prices Based on Models and Other Valuation Methods" if there is
         absence of pricing information from external sources, modeled
         information is derived using valuation models developed by the
         reporting entity, reflecting when appropriate, option pricing theory,
         discounted cash flow concepts, valuation adjustments, etc. and may
         require projection of prices for underlying commodities beyond the
         period that prices are available from third-party sources. In addition,
         where external pricing information or market liquidity are limited,
         such valuations are classified as modeled. The determination of the
         point at which a market is no longer liquid for placing it in the
         Modeled category varies by market.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).

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

<TABLE>
<CAPTION>

                                                     Total Other Comprehensive Income (Loss) Activity
                                                              Six Months Ended June 30, 2003

                                                        Domestic          Foreign
                                                          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)                         (2,229)             -                    (1,156)              (3,385)
        Reclassifications from OCI to Net
         Income (b)                                          138                3                     131                  272
                                                         -------             ----                  -------             -------
        Accumulated OCI Derivative Gain (Loss)
          June 30, 2003                                  $(2,485)           $(187)                $(2,361)             $(5,033)
                                                         =======            =====                 =======              =======
</TABLE>

(a)      "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
(b)      "Reclassifications from OCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $1,894 thousand loss.

Credit Risk

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

VaR Associated with Energy Trading Contracts

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

               June 30, 2003                      December 31, 2002
               (in thousands)                       (in thousands)
       End     High  Average    Low         End     High    Average  Low
       ---     ----  -------    ---         ---     ----    -------  ---
      $346   $2,354  $1,311    $346        $1,289  $3,948   $1,412  $286

<PAGE>
<TABLE>
<CAPTION>

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

                                                               Three Months Ended June 30,             Six Months Ended June 30,
                                                                2003                2002                2003               2002
                                                                ----                ----                ----               ----
                                                                                         (in thousands)
OPERATING REVENUES:
<S>                                                          <C>                  <C>                  <C>                 <C>
   Electric Generation, Transmission and
    Distribution                                             $  389,255           $  382,081           $868,588            $801,880
   Sales to AEP Affiliates                                       55,496               49,934            112,391              92,740
                                                             ----------           ----------           --------            --------
           TOTAL OPERATING REVENUES                             444,751              432,015            980,979             894,620
                                                             ----------           ----------           --------            --------

OPERATING EXPENSES:
   Fuel for Electric Generation                                 112,680              107,160            232,545             214,650
   Purchased Electricity for Resale                              15,262               14,945             32,380              28,461
   Purchased Electricity from AEP Affiliates                     83,805               58,717            164,525             119,497
   Other Operation                                               66,626               63,417            128,741             130,376
   Maintenance                                                   36,827               27,638             69,565              53,489
   Depreciation and Amortization                                 46,065               46,909             82,073              93,681
   Taxes Other Than Income Taxes                                 22,272               25,050             47,351              50,045
   Income Taxes                                                  12,158               22,955             62,059              57,643
                                                             ----------           ----------           --------            --------
           TOTAL OPERATING EXPENSES                             395,695              366,791            819,239             747,842
                                                             ----------           ----------           --------            --------

OPERATING INCOME                                                 49,056               65,224            161,740             146,778

NONOPERATING INCOME (LOSS)                                         (447)              14,933             (4,931)             20,017

NONOPERATING EXPENSES                                             2,328                  660              6,002               4,305

NONOPERATING INCOME TAX
 EXPENSE (CREDIT)                                                (2,451)               4,820             (6,184)              5,084

INTEREST CHARGES                                                 34,096               28,069             63,202              55,457
                                                             ----------           ----------           --------            --------

INCOME BEFORE CUMULATIVE EFFECT
 OF ACCOUNTING CHANGES                                           14,636               46,608             93,789             101,949

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

NET INCOME                                                       14,636               46,608            171,046             101,949

PREFERRED STOCK DIVIDEND
 REQUIREMENTS                                                       984                  503              1,968               1,006
                                                             ----------           ----------           --------            --------

EARNINGS APPLICABLE TO COMMON  STOCK                         $   13,652           $   46,105           $169,078            $100,943
                                                             ==========           ==========           ========            ========

</TABLE>

The common stock of APCo is wholly owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                          APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                          CONSOLIDATED STATEMENTS OF 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                                      $260,458       $715,786        $150,797           $  (340)        $1,126,701
Common Stock Dividends                                                               (61,968)                             (61,968)
Preferred Stock Dividends                                                               (720)                                (720)
Capital Stock Expense                                                    285            (285)                                -
                                                                                                                       ----------
                                                                                                                        1,064,013
                                                                                                                       ----------
Comprehensive Income:
  Other Comprehensive Income,
   Net of  Taxes:
    Unrealized Gain on Cash Flow Hedges                                                                    232                232
  Net Income                                                                         101,949                              101,949
                                                                                                                       ----------
     Total Comprehensive Income                                                                                           102,181
                                                     --------       --------        --------          --------         ----------

JUNE 30, 2002                                        $260,458       $716,071        $189,773          $   (108)        $1,166,194
                                                     ========       ========        ========          ========         ==========



JANUARY 1, 2003                                      $260,458       $717,242        $260,439          $(72,082)        $1,166,057
Common Stock Dividends                                                               (64,133)                             (64,133)
Preferred Stock Dividends                                                               (721)                                (721)
Capital Stock Expense                                                  1,247          (1,247)                                -
SFAS 71 Reapplication                                                    162                                                  162
                                                                                                                       ----------
                                                                                                                        1,101,365
                                                                                                                       ----------
Comprehensive Income:
  Other Comprehensive Income (Loss),
Net of Taxes:
    Unrealized Loss on Cash Flow Hedges                                                                 (3,113)            (3,113)
  Net Income                                                                         171,046                              171,046
                                                                                                                       ----------
     Total Comprehensive Income                                                                                           167,933
                                                     --------       --------        --------          --------         ----------

JUNE 30, 2003                                        $260,458       $718,651        $365,384          $(75,195)        $1,269,298
                                                     ========       ========        ========          ========         ==========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>
                                            APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                    CONSOLIDATED BALANCE SHEETS
                                                             (UNAUDITED)

                                                                                       June 30, 2003           December 31, 2002
                                                                                       -------------           -----------------
                                                                                                    (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                      <C>                         <C>
   Production                                                                            $2,268,852                  $2,245,945
   Transmission                                                                           1,223,020                   1,218,108
   Distribution                                                                           1,977,458                   1,951,804
   General                                                                                  276,249                     272,901
   Construction Work in Progress                                                            241,576                     206,545
                                                                                         ----------                  ----------
        Total Electric Utility Plant                                                      5,987,155                   5,895,303
   Accumulated Depreciation and Amortization                                              2,348,379                   2,424,607
                                                                                         ----------                  ----------
        NET ELECTRIC UTILITY PLANT                                                        3,638,776                   3,470,696
                                                                                         ----------                  ----------

OTHER PROPERTY AND INVESTMENTS                                                               51,733                      54,653
                                                                                         ----------                  ----------

LONG-TERM RISK MANAGEMENT ASSETS                                                            103,273                     115,748
                                                                                         ----------                  ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                 10,670                       4,285
   Advances to Affiliates                                                                   118,665                        -
   Accounts Receivable:
      Customers                                                                             115,387                     132,266
      Affiliated Companies                                                                   77,579                     122,665
      Miscellaneous                                                                          43,165                      28,629
      Allowance for Uncollectible Accounts                                                   (2,454)                    (13,439)
   Fuel Inventory                                                                            38,774                      53,646
   Materials and Supplies                                                                    71,793                      59,886
   Accrued Utility Revenues                                                                   2,827                      30,948
   Risk Management Assets                                                                    87,617                      94,238
   Prepayments and Other                                                                     13,896                      13,396
                                                                                         ----------                  ----------
        TOTAL CURRENT ASSETS                                                                577,919                     526,520
                                                                                         ----------                  ----------

REGULATORY ASSETS                                                                           407,667                     395,553
                                                                                         ----------                  ----------

DEFERRED CHARGES                                                                             53,435                      64,677
                                                                                         ----------                  ----------

        TOTAL ASSETS                                                                     $4,832,803                  $4,627,847
                                                                                         ==========                  ==========
</TABLE>
See Notes to Respective Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
                                                 APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                        CONSOLIDATED BALANCE SHEETS
                                                                (UNAUDITED)

                                                                                             June 30, 2003       December 31, 2002
                                                                                             -------------       -----------------
                                                                                                       (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                                                            <C>                     <C>
   Common Stock - No Par Value:
      Authorized - 30,000,000 Shares
      Outstanding - 13,499,500 Shares                                                          $  260,458              $  260,458
   Paid-in Capital                                                                                718,651                 717,242
   Accumulated Other Comprehensive Income (Loss)                                                  (75,195)                (72,082)
   Retained Earnings                                                                              365,384                 260,439
                                                                                               ----------              ----------
        Total Common Shareowner's Equity                                                        1,269,298               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                                                                               1,822,927               1,738,854
                                                                                               ----------              ----------

           TOTAL CAPITALIZATION                                                                 3,120,875               2,933,561
                                                                                               ----------              ----------

OTHER NONCURRENT LIABILITIES                                                                      190,988                 173,438
                                                                                               ----------              ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                                             155,008                 155,007
   Advances from Affiliates                                                                          -                     39,205
   Accounts Payable - General                                                                      98,494                 141,546
   Accounts Payable - Affiliated Companies                                                         61,798                  98,374
   Taxes Accrued                                                                                   62,484                  29,181
   Customer Deposits                                                                               39,068                  26,186
   Interest Accrued                                                                                24,692                  22,437
   Risk Management Liabilities                                                                     65,037                  69,001
   Other                                                                                           66,729                  79,832
                                                                                               ----------              ----------

           TOTAL CURRENT LIABILITIES                                                              573,310                 660,769
                                                                                               ----------              ----------

DEFERRED INCOME TAXES                                                                             754,648                 701,801
                                                                                               ----------              ----------

DEFERRED INVESTMENT TAX CREDITS                                                                    32,844                  33,691
                                                                                               ----------              ----------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                              56,692                  44,517
                                                                                               ----------              ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                       103,446                  80,070
                                                                                               ----------              ----------

COMMITMENTS AND CONTINGENCIES (Note 7)

        TOTAL CAPITALIZATION AND LIABILITIES                                                   $4,832,803              $4,627,847
                                                                                               ==========              ==========
</TABLE>

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                                         APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                           CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                        (UNAUDITED)

                                                                                              Six Months Ended June 30,
                                                                                            2003                    2002
                                                                                            ----                    ----
                                                                                                   (in thousands)
OPERATING ACTIVITIES:
<S>                                                                                    <C>                       <C>
   Net Income                                                                          $ 171,046                 $ 101,949
   Adjustments to Reconcile Net Income to Net Cash Flows
    From Operating Activities:
      Cumulative Effect of Accounting Changes                                            (77,257)                     -
      Depreciation and Amortization                                                       82,073                    93,737
      Deferred Income Taxes                                                                2,305                    (7,055)
      Deferred Investment Tax Credits                                                       (847)                   (2,196)
      Deferred Power Supply Costs, net                                                    69,528                       915
      Mark to Market of Risk Management Contracts                                         19,433                   (12,797)
   Changes in Certain Assets and Liabilities:
      Accounts Receivable, net                                                            36,444                  (168,502)
      Fuel, Materials and Supplies                                                         2,965                    20,384
      Accrued Utility Revenues                                                            28,121                     7,988
      Accounts Payable                                                                   (79,628)                   53,045
      Taxes Accrued                                                                       33,303                    35,244
      Interest Accrued                                                                     2,255                     6,410
      Incentive Plan Accrued                                                              (9,388)                   (5,524)
      Rate Stabilization Deferral                                                        (75,601)                     -
   Change in Other Assets                                                                  7,404                   (14,767)
   Change in Other Liabilities                                                            50,349                    12,973
                                                                                       ---------                 ---------
           Net Cash Flows From Operating Activities                                      262,505                   121,804
                                                                                       ---------                 ---------

INVESTING ACTIVITIES:
   Construction Expenditures                                                            (114,806)                 (128,853)
   Proceeds from Sale of Property and Other                                                1,648                       583
                                                                                       ---------                 ---------
           Net Cash Flows Used For Investing Activities                                 (113,158)                 (128,270)
                                                                                       ---------                 ---------

FINANCING ACTIVITIES:
   Issuance of Long-term Debt                                                            500,000                   444,110
   Change in Advances to/from Affiliates                                                (157,870)                 (387,315)
   Retirement of Long-term Debt                                                         (420,238)                     -
   Dividends Paid on Common Stock                                                        (64,133)                  (61,968)
   Dividends Paid on Cumulative Preferred Stock                                             (721)                     (720)
                                                                                       ---------                 ---------
           Net Cash Flows Used For Financing Activities                                 (142,962)                   (5,893)
                                                                                       ---------                 ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                       6,385                   (12,359)
Cash and Cash Equivalents at Beginning of Period                                           4,285                    13,663
                                                                                       ---------                 ---------
Cash and Cash Equivalents at End of Period                                             $  10,670                 $   1,304
                                                                                       =========                 =========
</TABLE>

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $56,152,000 and
$47,676,000 and for income taxes was $21,102,000 and $36,585,000 in 2003 and
2002, respectively.

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

<PAGE>

                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
            MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations
---------------------

Net Income increased $9 million year-to-date including Cumulative Effect of
Accounting Changes of $27 million recorded in the first quarter 2003 (see Note
3). Income Before Cumulative Effect decreased $18 million due to reduced income
from energy trading outside of the AEP territory. Net Income for the quarter
decreased $22 million due to decreased retail sales and lower revenues from
energy trading as a result of cooler weather and a continued sluggish economy.
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.

Operating Income

Operating Income decreased by $15 million for the quarter and $5 million
year-to-date primarily due to the following:

o     Milder weather and a slower-than-expected economic recovery
      resulting in decreased retail revenues of $19 million during the
      second quarter. Year-to-date retail revenues decreased $10 million
      due to a slower-than-expected economic recovery and a mild second
      quarter partially offset by favorable colder weather in the first
      quarter.
o     Fuel for Electric Generation increased $7 million year-to-date, due to
      increased generation and higher coal costs.
o     Purchased  Electricity  from AEP  Affiliates was $9 million higher in
      the quarter and $20 million higher  year-to-date  due to price and volume
      increases along with higher capacity charges.
o     Maintenance expense increased $8 million during the quarter and
      year-to-date due to scheduled boiler overhaul work and maintenance of
      overhead lines.
o     Taxes Other Than Income Taxes increased $2 million during the quarter
      due to higher property taxes. Taxes Other Than Income Taxes increased
      $7 million year-to-date due to higher property taxes and state excise
      taxes.

The decrease in Operating Income was partially offset by:
o     Increased AEP Power Pool revenues of $9 million ($7 million to
      non-affiliated customers and $2 million to affiliated customers)
      and $29 million ($19 million to non-affiliated customers and $10
      million to affiliated customers) for the quarter and year-to-date
      periods, respectively.
o     Other Operation expense decreased $9 million during the quarter due to
      reduced  factoring expense from lower interest rates, reduced post
      retirement  benefits expense and reduced legal expenses.
o     During the quarter, Income Taxes decreased by $7 million due to a
      decrease in pre-tax operating book income.

Other Impacts on Earnings

Nonoperating Income, net of expenses and taxes, decreased $8 million for the
quarter and $13 million year-to-date primarily due to the following:

o     Net revenues  resulting from risk management activities decreased $11
      million and $24 million for the quarter and  year-to-date, respectively,
      as a result of AEP's decision to exit wholesale markets where it does
      not own assets.
o     Nonoperating  Income Tax Expense decreased $3 million and $10 million
      for the quarter and year-to-date, respectively, 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).

Financial Condition
-------------------

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                            Moody's       S&P         Fitch
                                            -------       ---         -----

         First Mortgage Bonds               A3            BBB         A
         Senior Unsecured Debt              A3            BBB         A-

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.

Financing Activities

In February 2003, we 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%. The proceeds from the issuances were used to repay a bank facility,
short-term debt and for other corporate purposes.

In 2003, we redeemed or repaid the following first mortgage bonds:
<TABLE>
<CAPTION>

            Coupon or Stated Rate          Call Rate           Due Date      Principal Amounts
            ---------------------          ---------           --------      -----------------
                       %                      %                                (in millions)
                       -                      -
                     <C>                    <C>                  <C>                <C>
                     6.80                   100                  2003               $13
                     6.55                   100                  2004                26
                     6.75                   100                  2004                26
                     7.75                   104.27               2023                33
                     7.90                   103.95               2023                40
                     8.70                   104.35               2022                 2
                     8.55                   104.28               2022                15
                     8.40                   104.20               2022                14
                     8.40                   104.20               2022                13
</TABLE>

See Note 12 for additional information related to financing activity.

Significant Factors
-------------------

Federal EPA Complaint and Notice of Violation

As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", CSPCo, and certain affiliated companies have been
involved in litigation since 1999 regarding generating plant emissions under the
Clean Air Act. Federal EPA and a number of states alleged CSPCo, certain
affiliated companies 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 us 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 we do not prevail, any capital and operating costs of
additional pollution control equipment that may be required, as well as any
penalties imposed, would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity. See Note 7 for
further discussion.

NOx Reductions

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.

We are installing non-selective catalytic reduction 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 of approximately $87 million. The actual cost to comply
could be significantly different than the estimate 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.

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets

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





               Roll-Forward of MTM Risk Management Contract Net Assets
                            Six Months Ended June 30, 2003

        Domestic Power                                            CSPCo
        --------------                                            -----
                                                             (in thousands)
        Beginning Balance December 31, 2002                     $ 65,117
        -----------------------------------
        (Gain) Loss from Contracts Realized/Settled
         During the Period (a)                                   (26,884)
        Fair Value of New Contracts When Entered Into
        During the Period (b)                                       -
        Net Option Premiums Paid/(Received) (c)                      278
        Change in Fair Value Due to Valuation
         Methodology  Changes                                       -
        Effect of 98-10 Rescission                                (3,135)
        Changes in Fair Value of Risk Management
         Contracts (d)                                             7,390
        Changes in Fair Value Risk Management Contracts
        Allocated to Regulated  Jurisdictions (e)                   -
                                                                ---------
        Total MTM Risk Management Contract Net
          Assets                                                  42,766
        Net Non-Trading Related Derivative
          Contracts                                               (2,096)
                                                                --------
        Net Fair Value of Risk Management and  Derivative
         Contracts Ending Balance
         June 30, 2003                                          $ 40,670
                                                                ========

        (a)"(Gain) Loss from Contracts Realized/Settled During the Period"
            includes realized gains from risk management contracts and related
            derivatives that settled during 2003 that were entered into prior to
            2003.
        (b) The "Fair Value of New Contracts When Entered Into During the
            Period" represents the fair value of long-term contracts entered
            into with customers during 2003. The fair value is calculated as of
            the execution of the contract. Most of the fair value comes from
            longer term fixed price contracts with customers that seek to limit
            their risk against fluctuating energy prices. The contract prices
            are valued against market curves associated with the delivery
            location.
        (c) "Net Option Premiums Paid/(Received)" reflects the net option
            premiums paid/(received) as they relate to unexercised and unexpired
            option contracts that were entered into in 2003.
        (d)"Changes in Fair Value of Risk Management Contracts" represents the
            fair value change in the risk management portfolio due to market
            fluctuations during the current period. Market fluctuations are
            attributable to various factors such as supply/demand, weather, etc.
        (e)"Change in Fair Value of Risk Management Contracts Allocated to
            Regulated Jurisdictions" relates to the net gains (losses) of those
            contracts that are not reflected in the Consolidated Statements of
            Income. These net gains (losses) are recorded as regulatory
            liabilities/assets for those subsidiaries that operate in regulated
            jurisdictions.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

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

<TABLE>
<CAPTION>
                                             Maturity and Source of Fair Value of MTM
                                               Risk Management Contract Net Assets
                                           Fair Value of Contracts as of June 30, 2003

                                                 Remainder                                                        After
                                                  2003            2004        2005        2006         2007       2007     Total
                                                  ----            ----        ----        ----         ----       ----     -----
                                                                               (in thousands)
<S>                                               <C>           <C>        <C>         <C>          <C>          <C>       <C>
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                          $9,129        $10,388    $3,330      $2,954       $  944       $ -       $26,745
Prices Based on Models and Other
 Valuation Methods (b)                               591          1,307     1,454       2,523        2,551        7,595     16,021
                                                  ------        -------    ------      ------       ------       ------    -------

    Total                                         $9,720        $11,695    $4,784      $5,477       $3,495       $7,595    $42,766
                                                  ======        =======    ======      ======       ======       ======    =======
</TABLE>

     (a) "Prices Provided by Other External Sources - OTC Broker Quotes"
         reflects information obtained from over-the-counter brokers, industry
         services, or multiple-party on-line platforms.
     (b) "Prices Based on Models and Other Valuation Methods" if there is
         absence of pricing information from external sources, modeled
         information is derived using valuation models developed by the
         reporting entity, reflecting when appropriate, option pricing theory,
         discounted cash flow concepts, valuation adjustments, etc. and may
         require projection of prices for underlying commodities beyond the
         period that prices are available from third-party sources. In addition,
         where external pricing information or market liquidity are limited,
         such valuations are classified as modeled. The determination of the
         point at which a market is no longer liquid for placing it in the
         Modeled category varies by market.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).

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.

                Total Other Comprehensive Income (Loss) Activity
                         Six Months Ended June 30, 2003

                                                        Domestic
                                                          Power
                                                     (in thousands)
        Accumulated OCI, December 31, 2002               $  (267)
        ----------------------------------
        Changes in Fair Value (a)                         (1,274)
        Reclassifications from OCI to Net
         Income (b)                                           81
                                                         -------
        Accumulated OCI Derivative Gain  (Loss)
         June 30, 2003                                   $(1,460)
                                                         =======

(a)      "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
(b)      "Reclassifications from OCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $993 thousand loss.

Credit Risk

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

VaR Associated with Energy Trading Contracts

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

                           June 30, 2003                                                             December 31, 2002
                           (in thousands)                                                             (in thousands)
             End        High       Average      Low                                         End        High       Average    Low
             ---        ----       -------      ---                                         ---        ----       -------    ---

<S>         <C>        <C>         <C>          <C>                                        <C>       <C>            <C>     <C>
            $203       $1,384      $771         $203                                       $867      $2,654         $949    $192

</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                         CONSOLIDATED STATEMENTS OF INCOME
                                                                   (UNAUDITED)

                                                                    Three Months Ended June 30,        Six Months Ended June 30,
                                                                   2003                 2002              2003                2002
                                                                   ----                 ----              ----                ----
                                                                                           (in thousands)
OPERATING REVENUES:
<S>                                                            <C>                 <C>                 <C>               <C>
    Electric Generation, Transmission and Distribution         $  313,359          $  326,538          $  651,796        $  633,686
    Sales to AEP Affiliates                                        19,712              17,275              40,480            24,953
                                                               ----------          ----------          ----------        ----------
           TOTAL OPERATING REVENUES                               333,071             343,813             692,276           658,639
                                                               ----------          ----------          ----------        ----------

OPERATING EXPENSES:
    Fuel for Electric Generation                                   44,024              43,064              96,067            88,714
    Purchased Electricity for Resale                                4,012               3,826               8,210             7,555
    Purchased Electricity from AEP Affiliates                      87,590              78,622             169,739           150,204
    Other Operation                                                52,294              61,788             108,679           115,649
    Maintenance                                                    22,612              15,050              37,171            29,190
    Depreciation and Amortization                                  33,299              32,402              67,036            65,138
    Taxes Other Than Income Taxes                                  30,954              29,330              66,562            59,606
    Income Taxes                                                   14,869              21,691              40,244            38,995
                                                               ----------          ----------          ----------        ----------
           TOTAL OPERATING EXPENSES                               289,654             285,773             593,708           555,051
                                                               ----------          ----------          ----------        ----------

OPERATING INCOME                                                   43,417              58,040              98,568           103,588

NONOPERATING INCOME (LOSS)                                            259               9,317              (6,756)           14,391

NONOPERATING EXPENSES (CREDITS)                                       532              (1,206)              2,394               418

NONOPERATING INCOME TAX EXPENSE (CREDIT)                              400               3,450              (5,147)            4,797

INTEREST CHARGES                                                   13,413              13,392              26,875            27,185
                                                               ----------          ----------          ----------        ----------

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES              29,331              51,721              67,690            85,579

CUMULATIVE EFFECT OF ACCOUNTING  CHANGES (NET OF TAX)                -                   -                 27,283              -
                                                               ----------          ----------          ----------        ----------

NET INCOME                                                         29,331              51,721              94,973            85,579

PREFERRED STOCK DIVIDEND  REQUIREMENTS (INCLUDING
CAPITAL STOCK EXPENSE)                                                254                 429                 508               858
                                                               ----------          ----------          ----------        ----------

EARNINGS APPLICABLE TO COMMON  STOCK
                                                               $   29,077          $   51,292          $   94,465        $   84,721
                                                               ==========          ==========          ==========        ==========
</TABLE>
The common stock of CSPCo is wholly owned by AEP.

See Notes to Respective Financial Statements beginning on Page L-1.

<TABLE>
<CAPTION>
                                         COLUMBUS SOUTHERN POWER 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                                       $41,026       $574,369        $176,103           $  -              $791,498
Common Stock Dividends Declared                                                      (43,534)                             (43,534)
Preferred Stock Dividends Declared                                                      (350)                                (350)
Capital Stock Expense                                                    508            (508)                                -
                                                                                                                         --------
                                                                                                                          747,614
                                                                                                                         --------
Comprehensive Income:
  Other Comprehensive Income, Net of Taxes:
  Unrealized Gain on Cash Flow Power Hedges                                                              1,449              1,449
  Net Income                                                                          85,579                               85,579
                                                                                                                         --------
     Total Comprehensive Income                                                                                            87,028
                                                      -------       --------        --------          --------           --------

JUNE 30, 2002                                         $41,026       $574,877        $217,290          $  1,449           $834,642
                                                      =======       ========        ========          ========           ========



JANUARY 1, 2003                                       $41,026       $575,384        $290,611          $(59,357)          $847,664
Common Stock Dividends Declared                                                      (86,622)                             (86,622)
Capital Stock Expense                                                    508            (508)                                -
                                                                                                                         --------
                                                                                                                          761,042
                                                                                                                         --------
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
     Power Hedges                                                                                       (1,193)            (1,193)
    Net Income                                                                        94,973                               94,973
                                                                                                                         --------
       Total Comprehensive Income                                                                                          93,780
                                                      -------       --------        --------          --------           --------

JUNE 30, 2003                                         $41,026       $575,892        $298,454          $(60,550)          $854,822
                                                      =======       ========        ========          ========           ========
</TABLE>

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                          COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                   CONSOLIDATED BALANCE SHEETS
                                                           (UNAUDITED)

                                                                                             June 30, 2003      December 31, 2002
                                                                                             -------------      -----------------
                                                                                                        (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                            <C>                     <C>
   Production                                                                                  $1,592,165              $1,582,627
   Transmission                                                                                   415,067                 413,286
   Distribution                                                                                 1,230,377               1,208,255
   General                                                                                        155,721                 165,025
   Construction Work in Progress                                                                  119,049                  98,433
                                                                                               ----------              ----------
       Total Electric Utility Plant                                                             3,512,379               3,467,626
   Accumulated Depreciation and Amortization                                                    1,448,956               1,465,174
                                                                                               ----------              ----------
        NET ELECTRIC UTILITY PLANT                                                              2,063,423               2,002,452
                                                                                               ----------              ----------

OTHER PROPERTY AND INVESTMENTS                                                                     33,293                  35,759
                                                                                               ----------              ----------

LONG-TERM RISK MANAGEMENT ASSETS                                                                   60,705                  77,810
                                                                                               ----------              ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                        7,485                   1,479
   Advances to Affiliates, net                                                                       -                     31,257
   Accounts Receivable:
      Customers                                                                                    37,191                  49,566
      Affiliated Companies                                                                         40,659                  54,518
      Miscellaneous                                                                                20,112                  22,005
      Allowance for Uncollectible Accounts                                                           (609)                   (634)
   Fuel                                                                                            17,162                  24,844
   Materials and Supplies                                                                          47,016                  40,339
   Accrued Utility Revenues                                                                         6,436                  12,671
   Risk Management Assets                                                                          51,519                  63,348
   Prepayments and Other                                                                            8,944                   7,308
                                                                                               ----------              ----------
        TOTAL CURRENT ASSETS                                                                      235,915                 306,701
                                                                                               ----------              ----------

REGULATORY ASSETS                                                                                 252,591                 257,682
                                                                                               ----------              ----------

DEFERRED CHARGES                                                                                   50,785                  72,836
                                                                                               ----------              ----------

        TOTAL ASSETS                                                                           $2,696,712              $2,753,240
                                                                                               ==========              ==========
</TABLE>

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                               COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                           CONSOLIDATED BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                    June 30, 2003           December 31, 2002
                                                                                    -------------           -----------------
                                                                                                (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                                                     <C>                      <C>
   Common Stock - No Par Value:
      Authorized - 24,000,000 Shares
      Outstanding - 16,410,426 Shares                                                   $   41,026               $   41,026
   Paid-in Capital                                                                         575,892                  575,384
   Accumulated Other Comprehensive Income (Loss)                                           (60,550)                 (59,357)
   Retained Earnings                                                                       298,454                  290,611
                                                                                        ----------               ----------
        Total Common Shareholder's Equity                                                  854,822                  847,664
   Long-term Debt                                                                          747,736                  418,626
   Long-term Debt - Affiliated Companies                                                      -                     160,000
                                                                                        ----------               ----------

           TOTAL CAPITALIZATION                                                          1,602,558                1,426,290
                                                                                        ----------               ----------

OTHER NONCURRENT LIABILITIES                                                                90,243                   95,460
                                                                                        ----------               ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                                       30,000                   43,000
   Short-term Debt - Affiliates                                                               -                     290,000
   Advances from Affiliates, net                                                           115,014                     -
   Accounts Payable - General                                                               57,710                   89,736
   Accounts Payable - Affiliated                                                            74,299                   81,599
   Taxes Accrued                                                                            87,376                  112,172
   Interest Accrued                                                                         17,467                    9,798
   Risk Management Liabilities                                                              38,230                   46,375
   Other                                                                                    49,942                   36,790
                                                                                        ----------               ----------

           TOTAL CURRENT LIABILITIES                                                       470,038                  709,470
                                                                                        ----------               ----------

DEFERRED INCOME TAXES                                                                      451,884                  437,771
                                                                                        ----------               ----------

DEFERRED INVESTMENT TAX CREDITS                                                             32,381                   33,907
                                                                                        ----------               ----------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                       33,324                   29,926
                                                                                        ----------               ----------

DEFERRED CREDITS AND REGULATORY LIABILITIES                                                 16,284                   20,416
                                                                                        ----------               ----------

COMMITMENTS AND CONTINGENCIES (Note 7)

           TOTAL CAPITALIZATION AND LIABILITIES                                         $2,696,712               $2,753,240
                                                                                        ==========               ==========
</TABLE>

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                  CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                              (UNAUDITED)

                                                                                                  Six Months Ended June 30,
                                                                                                2003                     2002
                                                                                                ----                     ----
OPERATING ACTIVITIES:                                                                                  (in thousands)
<S>                                                                                            <C>                      <C>
   Net Income                                                                                  $ 94,973                 $ 85,579
   Adjustments to Reconcile Net Income to Net Cash Flows
    From Operating Activities:
      Cumulative Effect of Accounting Changes                                                   (27,283)                    -
      Depreciation and Amortization                                                              67,036                   65,192
      Deferred Income Taxes                                                                      (3,135)                  (5,432)
      Deferred Investment Tax Credits                                                            (1,526)                  (1,557)
      Mark-to-Market of Risk Management Contracts                                                19,215                  (11,260)
   Changes in Certain Assets and Liabilities:
      Accounts Receivable, net                                                                   28,102                 (102,607)
      Fuel, Materials and Supplies                                                                1,005                   (2,577)
      Accrued Utility Revenues                                                                    6,235                  (10,289)
      Prepayments and Other Current Assets                                                       (1,636)                  (9,186)
      Accounts Payable                                                                          (39,326)                  48,171
      Taxes Accrued                                                                             (24,796)                 (33,183)
      Interest Accrued                                                                            7,669                       89
      Deferred Property Tax                                                                      30,973                   23,971
   Change in Other Assets                                                                       (11,697)                  (7,865)
   Change in Other Liabilities                                                                   (1,650)                   3,440
                                                                                               --------                 --------
           Net Cash Flows From Operating Activities                                             144,159                   42,486
                                                                                               --------                 --------

INVESTING ACTIVITIES:
   Construction Expenditures                                                                    (65,492)                 (55,842)
   Proceeds from Sale of Property                                                                   190                      389
                                                                                               --------                 --------
           Net Cash Flows Used For Investing Activities                                         (65,302)                 (55,453)
                                                                                               --------                 --------

FINANCING ACTIVITIES:
   Issuance of Long-term Debt                                                                   500,000                     -
   Change in Advances to/from Affiliates, net                                                   146,271                 (202,093)
   Retirement of Long-term Debt                                                                (182,500)                    -
   Change in Short-term Debt - Affiliates                                                      (290,000)                 250,000
   Retirement of Long-term Debt - Affiliated Companies                                         (160,000)                    -
   Dividends Paid on Common Stock                                                               (86,622)                 (43,534)
   Dividends Paid on Cumulative Preferred Stock                                                    -                        (350)
                                                                                               --------                 --------
           Net Cash Flows From (Used For) Financing Activities                                  (72,851)                   4,023
                                                                                               --------                 --------

Net Increase (Decrease) in Cash and Cash Equivalents                                              6,006                   (8,944)
Cash and Cash Equivalents at Beginning of Period                                                  1,479                   12,358
                                                                                               --------                 --------
Cash and Cash Equivalents at End of Period                                                     $  7,485                 $  3,414
                                                                                               ========                 ========
</TABLE>

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $18,442,000 and
$26,262,000 and for income taxes was $9,245,000 and $32,254,000 in 2003 and
2002, respectively.

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

                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations
---------------------

In the second quarter of 2003, Net Income decreased $9 million reflecting mild
spring weather, higher fuel and purchased power costs, a weak economy and the
impact of plant availability. Net Income increased $8 million including an
unfavorable $3 million Cumulative Effect of Accounting Change in the first six
months of 2003 (see Note 3). Net Income (Loss) Before Cumulative Effect of
Accounting Change increased $11 million 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 partially offset by the
weak economy. We, as a member of the AEP Power Pool, share in the revenues and
costs of marketing and activities conducted on our behalf by the AEP Power Pool.
During the second quarter of 2003, both units of Cook Plant were unavailable due
to a forced outage which impacted operating income significantly. See
significant factors below.

Operating Income

Operating Income decreased by less than $1 million in the second quarter
primarily due to the following:

o   Increased Fuel for Electric Generation expense of $13 million reflecting
    an increase in the average cost of fuel.
o   Increased Purchased Electricity from AEP Affiliates of $10 million due to
    purchasing replacement power during outages at both units of Cook Plant.
o   A $7 million decrease in Electric Generation, Transmission and Distribution
    revenues due to milder weather during the second quarter of 2003.

The decrease in Operating Income during the second quarter was partially offset
by:

o   Sales to AEP Affiliates increased by $15 million due to increased capacity
    revenue and increased sales volume to the AEP Power Pool and western
    affiliates.
o   A decline in Other Operation expense of $13 million due to the favorable
    effect of cost reduction efforts instituted in the fourth quarter of 2002.
o   A $6 million decrease in Taxes Other Than Income Taxes due to 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.

Operating Income increased by $28 million year-to-date primarily due to the
following:

o   Electric Generation, Transmission and Distribution revenues increased
    $38 million due to an increase in sales reflecting a colder winter.
o   Sales to AEP Affiliates increased by $37 million due to more power
    being available for sale in 2003 and our share of sales to our
    western affiliates. In the first quarter of 2002, one unit of Cook
    plant was shut down for refueling and both Rockport units were
    down for planned boiler maintenance.
o   A decline in Other Operation expense of $22 million due to the impact of
    cost reduction efforts instituted in the fourth  quarter of 2002 and
    having two refueling outages in 2002 verses one refueling outage in 2003.
o   A $7 million  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.

The year-to-date increase in Operating Income was partially offset by:

o   Increased Fuel for Electric Generation expense of $32 million reflecting
    an increase in the average cost of fuel and increased generation.
o   Increased  Purchased Electricity from AEP Affiliates of $23 million
    due to higher power purchases from AEGCo in 2003 compared to 2002 when
    outages at both units of the Rockport Plant decreased available power and
    purchases of replacement power during the 2003 Cook outages.
o   Increased Income Taxes of $13 million reflecting an increase in pre-tax
    income.

Other Impacts on Earnings

Nonoperating Income decreased $8 million in the second quarter and $22 million
year-to-date primarily 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.

Interest Charges decreased $2 million in the second quarter primarily due to a
reduction in outstanding long-term debt of $255 million retired in May 2003.

Cumulative Effect of Accounting Change

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

Financial Condition
-------------------
Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                            Moody's       S&P         Fitch
                                            -------       ---         -----
         First Mortgage Bonds               Baa1          BBB         BBB+
         Senior Unsecured Debt              Baa2          BBB         BBB

During the first quarter of 2003, Moody's Investors Service (Moody's), Standard
& Poors (S&P) and Fitch Rating Service completed their reviews of AEP and its
rated subsidiaries. The reviews resulted in downgrades of debt ratings. The
completion of these reviews was a culmination of ratings action started during
2002.

Cash Flow

Cash flows for six months ended June 30, 2003 and 2002 were as follows:
<TABLE>
<CAPTION>

                                                                                   2003              2002
                                                                              --------------    --------------
                                                                                       (in thousands)
           <S>                                                                  <C>                <C>
           Cash and cash equivalents at beginning of period                     $  3,237           $ 16,804
                                                                                --------           --------
           Cash flow from (used for):
             Operating activities                                                 88,838              9,204
             Investing activities                                                (70,831)           (67,396)
             Financing activities                                                (15,513)            55,096
                                                                                --------           --------
           Net increase (decrease) in cash and cash  equivalents                   2,494             (3,096)
                                                                                --------           --------

           Cash and cash equivalents at end of period                           $  5,731           $ 13,708
                                                                                ========           ========
</TABLE>


Operating Activities

Operating activities during the first half of 2003 provided $80 million more
cash than during the first half of 2002 largely due to the year-over-year
increase in net income of $8 million and decreases in various Regulatory Assets.


Investing Activities

Cash flows used for investing activities during the first half of 2003 were $71
million compared to $67 million during the first half of 2002. The primary
reason for the year-over-year variance was a construction expenditures increase
of $4 million.

Financing Activities

Financing activities in the first half of 2003 used $71 million more than in the
first half of 2002 primarily due to:

o Retirement and restructuring of our short-term and long-term debt during 2003.
  We retired $255 million of long-term debt using short-term debt.
o Dividends paid on common stock of $20 million. Common dividends were not
  distributed in 2002.

Financing Activity

In May 2003, we retired $255 million of long-term debt prior to maturity using
short-term debt as shown in the following table:
<TABLE>
<CAPTION>

                                                       Coupon
                    Type of                           Or Stated           Call                                Principal
                     Debt                               Rate              Rate            Due Date             Amounts
                     ----                               -----             ----            --------             -------
                                                        %                  %                                (in millions)
                                                        -                  -
        <S>                                             <C>                <C>             <C>                     <C>
        First Mortgage Bonds                            8.50               100             2022                    $75
        First Mortgage Bonds                            7.35               100             2023                     15
        Junior Debentures                               8.00               100             2026                     40
        Junior Debentures                               7.60               100             2038                    125
</TABLE>

See Note 12 for additional information related to financing activity.

Significant Factors
-------------------

Nuclear Plant Outages

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

Federal EPA Complaint and Notice of Violation

As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", we have been involved in litigation since 1999
regarding generating plant emissions under the Clean Air Act. Federal EPA and a
number of states alleged I&M, certain affiliated companies 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 us 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 we do not prevail, any capital and operating costs of
additional pollution control equipment that may be required as well as any
penalties imposed would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity. See Note 7 for
further discussion.

NOx Reductions

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.

We are installing non-selective catalytic reduction 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 of
approximately $39 million. The actual cost to comply could be significantly
different than the estimate 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.

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets

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



          Roll-Forward of MTM Risk Management Contract Net Assets
                      Six Months Ended June 30, 2003

Domestic Power
--------------
                                                               (in thousands)
Beginning Balance December 31, 2002                               $ 70,861
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
 During the Period (a)                                             (25,361)
Fair Value of New Contracts When Entered Into
 During the Period (b)                                                -
Net Option Premiums Paid/(Received) (c)                                298
Change in Fair Value Due to Valuation
 Methodology  Changes                                                 -
Effect of 98-10 Rescission                                          (4,861)
Changes in Fair Value of Risk Management
 Contracts (d)                                                       5,264
Changes in Fair Value Risk Management Contracts
Allocated to Regulated  Jurisdictions (e)                              326
                                                                  --------
Total MTM Risk Management Contract Net
 Assets                                                             46,527
Net Non-Trading Related Derivative
 Contracts                                                          (2,241)
                                                                  --------
Net Fair Value of Risk Management and  Derivative
Contracts June 30, 2003                                          $ 44,286
                                                                  ========


    (a)"(Gain) Loss from Contracts Realized/Settled During the Period"
        includes realized gains from risk management contracts and related
        derivatives that settled during 2003 that were entered into prior to
        2003.
    (b) The "Fair Value of New Contracts When Entered Into During the
        Period" represents the fair value of long-term contracts entered
        into with customers during 2003. The fair value is calculated as of
        the execution of the contract. Most of the fair value comes from
        longer term fixed price contracts with customers that seek to limit
        their risk against fluctuating energy prices. The contract prices
        are valued against market curves associated with the delivery
        location.
    (c) "Net Option Premiums Paid/(Received)" reflects the net option
        premiums paid/(received) as they relate to unexercised and unexpired
        option contracts that were entered into in 2003.
    (d)"Changes in Fair Value of Risk Management Contracts" represents the
        fair value change in the risk management portfolio due to market
        fluctuations during the current period. Market fluctuations are
        attributable to various factors such as supply/demand, weather, etc.
    (e)"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.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
 o The source of fair value used in determining the carrying amount of our
   total MTM asset or liability (external sources or modeled internally).
 o The maturity, by year, of our net assets/liabilities, giving an indication
   of when these MTM amounts will settle and generate cash.
<TABLE>
<CAPTION>
                                                           Maturity and Source of Fair Value of MTM
                                                             Risk Management Contract Net Assets
                                                         Fair Value of Contracts as of June 30, 2003

                                               Remainder                                                        After
                                                 2003           2004         2005        2006         2007       2007      Total
                                                 ----           ----         ----        ----         ----       ----      -----
                                                                                    (in thousands)
<S>                                                <C>         <C>          <C>         <C>          <C>         <C>       <C>
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                           $10,556     $11,146      $3,564      $3,161       $1,010      $ -       $29,437
Prices Based on Models and Other
 Valuation Methods (b)                                 609       1,369       1,556       2,700        2,730       8,126     17,090
                                                   -------     -------      ------      ------       ------      ------    -------

    Total                                          $11,165     $12,515      $5,120      $5,861       $3,740      $8,126    $46,527
                                                   =======     =======      ======      ======       ======      ======    =======
</TABLE>

(a) "Prices Provided by Other External Sources" reflects information obtained
     from over-the-counter brokers, industry services, or multiple-party
     on-line platforms.
(b) "Prices Based on Models and Other  Valuation  Methods" if there is absence
     of pricing  information from external sources, modeled  information is
     derived using valuation models developed by the reporting entity,
     reflecting when appropriate, option pricing theory, discounted cash flow
     concepts, valuation adjustments, etc. and may require projection of
     prices for underlying commodities beyond the period that prices are
     available from third-party sources. In addition, where external pricing
     information or market liquidity are limited, such valuations are
     classified as modeled. The determination of the point at which a market
     is no longer liquid for placing it in the Modeled category varies by
     market.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).

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.

                Total Other Comprehensive Income (Loss) Activity
                         Six Months Ended June 30, 2003

                                                         Domestic
                                                          Power
                                                          -----
                                                     (in thousands)
        Accumulated OCI, December 31, 2002               $  (286)
        ----------------------------------
        Changes in Fair Value (a)                         (1,363)
        Reclassifications from OCI to Net
         Income (b)                                           87
                                                         -------
        Accumulated OCI Derivative Gain  (Loss)
        June 30, 2003                                    $(1,562)
                                                         =======

  (a) "Changes in Fair Value" shows changes in the fair value of derivatives
      designated as hedging instruments in cash flow hedges during the
      reporting period not yet reclassified into net income, pending the
      hedged item's affecting net income. Amounts are reported net of related
      income taxes.
  (b) "Reclassifications from OCI to Net Income" represents gains or losses
      from derivatives used as hedging instruments in cash flow hedges that
      were reclassified into net income during the reporting period. Amounts
      are reported net of related income taxes above.

The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $1,063 thousand loss.

Credit Risk

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

VaR Associated with Energy Trading Contracts

The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
<TABLE>
<CAPTION>
                         June 30, 2003                                                              December 31, 2002
                         (in thousands)                                                              (in thousands)
           End        High       Average      Low                                         End        High       Average    Low
           ---        ----       -------      ---                                         ---        ----       -------    ---
<S>       <C>        <C>          <C>         <C>                                        <C>       <C>          <C>       <C>
          $218       $1,481       $825        $218                                       $927      $2,840       $1,016    $206
</TABLE>



<PAGE>
<TABLE>
<CAPTION>
                                              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                  CONSOLIDATED STATEMENTS OF OPERATIONS
                                                                 (UNAUDITED)

                                                                  Three Months Ended June 30,             Six Months Ended June 30,
                                                                  2003                  2002              2003                2002
                                                                  ----                  ----              ----                ----
                                                                                           (in thousands)
OPERATING REVENUES:
<S>                                                              <C>                 <C>                <C>               <C>
   Electric Generation, Transmission and Distribution            $316,506            $323,642           $666,293          $628,668
   Sales to AEP Affiliates                                         60,400              45,401            129,211            92,610
                                                                 --------            --------           --------          --------

           TOTAL OPERATING REVENUES                               376,906             369,043            795,504           721,278
                                                                 --------            --------           --------          --------

OPERATING EXPENSES:
   Fuel for Electric Generation                                    65,763              53,163            138,857           107,319
   Purchased Electricity for Resale                                 7,035               4,551             13,317            10,680
   Purchased Electricity from AEP  Affiliates                      73,353              63,110            139,251           116,617
   Other Operation                                                108,532             121,180            209,913           232,099
   Maintenance                                                     42,595              39,580             73,962            70,623
   Depreciation and Amortization                                   42,841              41,870             86,567            83,736
   Taxes Other Than Income Taxes                                   12,149              17,855             28,970            36,096
   Income Taxes                                                     5,409               7,869             26,448            13,880
                                                                 --------            --------           --------          --------

           TOTAL OPERATING EXPENSES                               357,677             349,178            717,285           671,050
                                                                 --------            --------           --------          --------

OPERATING INCOME                                                   19,229              19,865             78,219            50,228

NONOPERATING INCOME                                                13,286              21,549             16,905            38,553

NONOPERATING EXPENSES                                              12,900               9,100             25,835            22,410

NONOPERATING INCOME TAX EXPENSE
 (CREDIT)                                                            (849)              1,313             (5,300)              888

INTEREST CHARGES                                                   21,655              23,507             45,093            46,931
                                                                 --------            --------           --------          --------

NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE                                                  (1,191)              7,494             29,496            18,552

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

NET INCOME (LOSS)                                                  (1,191)              7,494             26,336            18,552

PREFERRED STOCK DIVIDEND  REQUIREMENTS                              1,123               1,153              2,272             2,308
                                                                 --------            --------           --------          --------

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                       $ (2,314)           $  6,341           $ 24,064          $ 16,244
                                                                 ========            ========           ========          ========
</TABLE>

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

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

<TABLE>
<CAPTION>
                                            INDIANA MICHIGAN POWER 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                                       $56,584       $733,216        $ 74,605          $(3,835)         $  860,570
Preferred Stock Dividends                                                             (2,243)                              (2,243)
Capital Stock Expense                                                    275             (67)                                 208
                                                                                                                       ----------
                                                                                                                          858,535
                                                                                                                       ----------
Comprehensive Income:
  Other Comprehensive Income, Net of Taxes:
    Cash Flow Interest Rate Hedge                                                                       2,487               2,487
    Unrealized Gain on Cash Flow Power Hedges                                                           1,567               1,567
  Net Income                                                                          18,552                               18,552
                                                                                                                       ----------
     Total Comprehensive Income                                                                                            22,606
                                                      -------       --------        --------          -------          ----------

JUNE 30, 2002                                         $56,584       $733,491        $ 90,847          $   219          $  881,141
                                                      =======       ========        ========          =======          ==========



JANUARY 1, 2003                                       $56,584       $858,560        $143,996          $(40,487)        $1,018,653
Common Stock Dividends                                                               (20,000)                             (20,000)
Preferred Stock Dividends                                                             (2,205)                              (2,205)
Capital Stock Expense                                                     67             (67)                                -
                                                                                                                       ----------
                                                                                                                          996,448
                                                                                                                       ----------
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                      (1,276)            (1,276)
  Net Income                                                                          26,336                               26,336
                                                                                                                       ----------
     Total Comprehensive Income                                                                                            25,060
                                                      -------       --------        --------          --------         ----------

JUNE 30, 2003                                         $56,584       $858,627        $148,060          $(41,763)        $1,021,508
                                                      =======       ========        ========          ========         ==========
</TABLE>

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                               INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                        CONSOLIDATED BALANCE SHEETS
                                                                 (UNAUDITED)

                                                                                         June 30, 2003           December 31, 2002
                                                                                         -------------           -----------------
                                                                                                       (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                          <C>                       <C>
   Production                                                                                $2,866,216                $2,768,463
   Transmission                                                                                 977,471                   971,599
   Distribution                                                                                 938,692                   921,835
   General (including nuclear fuel)                                                             237,046                   220,137
   Construction Work in Progress                                                                168,824                   147,924
                                                                                             ----------                ----------
        Total Electric Utility Plant                                                          5,188,249                 5,029,958
   Accumulated Depreciation and Amortization                                                  2,681,293                 2,568,604
                                                                                             ----------                ----------
             NET ELECTRIC UTILITY PLANT                                                       2,506,956                 2,461,354
                                                                                             ----------                ----------

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
  DISPOSAL TRUST FUNDS                                                                          937,854                   870,754
                                                                                             ----------                ----------

LONG-TERM RISK MANAGEMENT ASSETS                                                                 65,110                    83,265
                                                                                             ----------                ----------

OTHER PROPERTY AND INVESTMENTS                                                                  114,019                   120,941
                                                                                             ----------                ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                      5,731                     3,237
   Advances to Affiliates                                                                          -                      191,226
   Accounts Receivable:
      Customers                                                                                  57,150                    67,333
      Affiliated Companies                                                                       73,760                   122,489
      Miscellaneous                                                                              22,978                    30,468
      Allowance for Uncollectible Accounts                                                         (567)                     (578)
   Fuel                                                                                          23,255                    32,731
   Materials and Supplies                                                                       103,429                    95,552
   Risk Management Assets                                                                        55,993                    68,148
   Prepayments and Other                                                                         10,148                    18,410
                                                                                             ----------                ----------
          TOTAL CURRENT ASSETS                                                                  351,877                   629,016
                                                                                             ----------                ----------

REGULATORY ASSETS                                                                               295,492                   348,212
                                                                                             ----------                ----------

DEFERRED CHARGES                                                                                 70,420                    73,649
                                                                                             ----------                ----------

          TOTAL ASSETS                                                                       $4,341,728                $4,587,191
                                                                                             ==========                ==========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>
                                                  INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                           CONSOLIDATED BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                         June 30, 2003           December 31, 2002
                                                                                         -------------           -----------------
                                                                                                     (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                                                        <C>                         <C>
   Common Stock - No Par Value:
      Authorized - 2,500,000 Shares
      Outstanding - 1,400,000 Shares                                                       $   56,584                  $   56,584
   Paid-in Capital                                                                            858,627                     858,560
   Accumulated Other Comprehensive Income (Loss)                                              (41,763)                    (40,487)
   Retained Earnings                                                                          148,060                     143,996
                                                                                           ----------                  ----------
        Total Common Shareowner's Equity                                                    1,021,508                   1,018,653
   Cumulative Preferred Stock:
      Not Subject to Mandatory Redemption                                                       8,101                       8,101
      Subject to Mandatory Redemption                                                          63,445                      64,945
   Long-term Debt                                                                           1,337,586                   1,587,062
                                                                                           ----------                  ----------

           TOTAL CAPITALIZATION                                                             2,430,640                   2,678,761
                                                                                           ----------                  ----------

OTHER NONCURRENT LIABILITIES:
   Asset Retirement Obligations                                                               534,321                        -
   Nuclear Decommissioning                                                                       -                        620,672
   Other                                                                                      129,155                     138,965
                                                                                           ----------                  ----------

           TOTAL OTHER NONCURRENT LIABILITIES                                                 663,476                     759,637
                                                                                           ----------                  ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                                          30,000                      30,000
   Advances from Affiliates                                                                    71,966                        -
   Accounts Payable:
      General                                                                                  72,073                     125,048
      Affiliated Companies                                                                     39,365                      93,608
   Taxes Accrued                                                                               52,358                      71,559
   Interest Accrued                                                                            19,664                      21,481
   Risk Management Liabilities                                                                 41,007                      48,568
   Other                                                                                       89,233                     101,051
                                                                                           ----------                  ----------

           TOTAL CURRENT LIABILITIES                                                          415,666                     491,315
                                                                                           ----------                  ----------

DEFERRED INCOME TAXES                                                                         327,745                     356,197
                                                                                           ----------                  ----------

DEFERRED INVESTMENT TAX CREDITS                                                                94,039                      97,709
                                                                                           ----------                  ----------

DEFERRED GAIN ON SALE AND LEASEBACK -
 ROCKPORT PLANT UNIT 2                                                                         72,032                      73,885
                                                                                           ----------                  ----------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                          35,810                      32,261
                                                                                           ----------                  ----------

DEFERRED CREDITS AND REGULATORY LIABILITIES                                                   302,320                      97,426
                                                                                           ----------                  ----------

CONTINGENCIES (Note 7)

                TOTAL CAPITALIZATION AND LIABILITIES                                       $4,341,728                  $4,587,191
                                                                                           ==========                  ==========
</TABLE>

See Notes to Respective Financial Statements beginning on page L-1.
<TABLE>
<CAPTION>
                                                      INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                           CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                        (UNAUDITED)

                                                                                                 Six Months Ended June 30,
                                                                                               2003                      2002
                                                                                               ----                      ----
                                                                                                        (in thousands)
OPERATING ACTIVITIES:
<S>                                                                                          <C>                      <C>
   Net Income                                                                                $  26,336                $  18,552
   Adjustments to Reconcile Net Income to Net Cash Flows
    From Operating Activities:
      Cumulative Effect of Accounting Change                                                     3,160                     -
      Depreciation and Amortization                                                             86,567                   83,779
      Deferral of Incremental Nuclear Refueling Outage Expenses, net                            (8,799)                 (45,701)
      Unrecovered Fuel and Purchased Power Costs                                                18,751                   18,751
      Amortization of Nuclear Outage Costs                                                      20,000                   20,000
      Deferred Income Taxes                                                                    (10,252)                  (7,723)
      Deferred Investment Tax Credits                                                           (3,670)                  (3,689)
      Mark-to-Market of Risk Management Contracts                                               19,474                    2,377
   Changes in Certain Assets and Liabilities:
      Accounts Receivable, net                                                                  66,391                 (189,078)
      Fuel, Materials and Supplies                                                               1,599                      189
      Accounts Payable                                                                        (107,218)                 134,183
      Taxes Accrued                                                                            (19,201)                  (1,713)
   Change in Other Assets                                                                      (51,976)                 (33,363)
   Change in Other Liabilities                                                                  47,676                   12,640
                                                                                             ---------                ---------
           Net Cash Flows From Operating Activities                                             88,838                    9,204
                                                                                             ---------                ---------

INVESTING ACTIVITIES:
      Construction Expenditures                                                                (71,246)                 (67,396)
      Other                                                                                        415                     -
                                                                                             ---------                ---------
           Net Cash Flows Used For Investing Activities                                        (70,831)                 (67,396)
                                                                                             ---------                ---------

FINANCING ACTIVITIES:
      Issuance of Long-term Debt                                                                  -                      49,648
      Retirement of Cumulative Preferred Stock                                                  (1,500)                    (424)
      Retirement of Long-term Debt                                                            (255,000)                 (50,000)
      Change in Advances to/from Affiliates, net                                               263,192                   58,115
      Dividends Paid on Common Stock                                                           (20,000)                    -
      Dividends Paid on Cumulative Preferred Stock                                              (2,205)                  (2,243)
                                                                                             ---------                ---------
           Net Cash Flows From (Used For) Financing Activities                                 (15,513)                  55,096
                                                                                             ---------                ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                             2,494                   (3,096)
Cash and Cash Equivalents at Beginning of Period                                                 3,237                   16,804
                                                                                             ---------                ---------
Cash and Cash Equivalents at End of Period                                                   $   5,731                $  13,708
                                                                                             =========                =========
</TABLE>

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $44,812,000 and
$42,695,000 and for income taxes was $50,731,000 and $18,711,000 in 2003 and
2002, respectively.

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

<PAGE>

                             KENTUCKY POWER COMPANY
            MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations
---------------------

Net Income for the second quarter and first half of 2003 decreased $1 million
and $2 million, respectively, from the corresponding periods of the prior year.
Net Income for the first half of 2003 included a loss from Cumulative Effect of
Accounting Change of $1 million (see Note 3). The declines from the prior
periods are primarily due to reduced gains from risk management activities
compared to the prior year partially offset by an improvement in earnings from
AEP Power Pool sales. We, as a member of the AEP Power Pool, share in the
revenues and costs of marketing and activities conducted on our behalf by the
AEP Power Pool.

Operating Income

Operating Income for the second quarter and six months ended June 30, 2003
increased $1 million and $6 million, respectively, primarily due to:

o   An increase in system sales of $5 million for the quarter and $12 million
    year-to-date.
o   A decrease in the current quarter in Maintenance expense of $1 million due
    to significant boiler overhaul work performed in the second quarter of 2002.
o   A decrease in Other Operation expense of $1 million from second quarter
    2002 due to lower employee benefits expense and decreased engineering
    expenses.
o   An increase in residential sales for the six-month period of $2 million
    reflecting increased first quarter 2003 demand resulting from more severe
    winter weather in 2003.

The increases in Operating Income were partially offset by:

o   A decline in retail sales of $2 million in the second quarter of 2003
    due to decreased residential sales reflecting the mild weather conditions
    and decreased industrial sales reflecting the slower-than-expected economic
    recovery.
o   Increases in Purchased Electricity from AEP Affiliates of $4 million and
    $12 million for the quarter and year-to-date, respectively, necessary to
    support sales during the Big Sandy plant outage for the NOx reduction
    upgrades. In addition, purchases increased from the Rockport Plant based
    on plant availability, as required by the unit power agreement with AEGCo,
    an affiliated company. The unit power agreement with AEGCo provides for
    our purchase of 15% of the total output of the two unit 2,600-MW capacity
    Rockport Plant.
o   An increase for the six months ended June 30, 2003 in Maintenance expense
    of $1 million  primarily due to  distribution  line  maintenance resulting
    from a major ice storm in February 2003.
o   Increased  Income  Taxes of $1 million and $3 million for the quarter and
    year-to-date,  respectively,  due to increases in pre-tax operating book
    income for both periods.

Other Impacts on Earnings

Nonoperating Income for the second quarter and first half of 2003 decreased $4
million and $8 million, respectively, primarily due to reduced gains from risk
management activities compared to the prior year. The decreases for the quarter
and six months in Nonoperating Income Tax Expense were a result of the decreases
in Nonoperating Income.

Cumulative Effect of Accounting Change

The Cumulative Effect of Accounting Change is due to the implementation of EITF
02-3 (see Note 3).

Financial Condition
-------------------

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                            Moody's       S&P         Fitch
                                            -------       ---         -----
         First Mortgage Bonds               Baa1          BBB         BBB+
         Senior Unsecured Debt              Baa2          BBB         BBB

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002.

Financing Activity

In June 2003, we issued $75 million in Senior Unsecured Notes due 2032. The
proceeds were used to retire $40 million of Junior Subordinated Debentures
(JSD), a $15 million Note Payable to AEP and to finance construction activities.

In April 2003, we called the following JSD for early redemption on May 30, 2003:

      Coupon
     Or Stated             Call                               Principal
       Rate                Rate           Due Date             Amounts
       -----               ----           --------             -------
         %                  %                               (in millions)
         -                  -
       8.72                100              2025                 $40

See Note 12 for additional information related to financing activity.

Significant Factors
-------------------

NOx Reductions

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 Kentucky where our generating plant is
located. The compliance date for the rules is May 31, 2004.

In May 2003, selective catalytic reduction (SCR) technology and non-SCR
technology to reduce NOx emissions at our Big Sandy plant commenced operation to
comply with these rules.

The capital expenditures for the SCR and non-SCR technology totaled $177 million
through June 30, 2003. In 2003, the KPSC granted recovery of approximately $18
million annually (see Note 5). See Note 7 for further discussion of emissions
control technology.

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets

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

                Roll-Forward of MTM Risk Management Contract Net Assets
                            Six Months Ended June 30, 2003

        Domestic Power
        --------------
                                                                (in thousands)
        Beginning Balance December 31, 2002                        $24,998
        -----------------------------------
        (Gain) Loss from Contracts Realized/Settled
         During the Period (a)                                      (8,989)
        Fair Value of New Contracts When Entered Into
         During the Period (b)                                        -
        Net Option Premiums Paid/(Received) (c)                        108
        Change in Fair Value Due to Valuation
         Methodology  Changes                                         -
        Effect of 98-10 Rescission                                  (1,744)
        Changes in Fair Value of Risk Management
         Contracts (d)                                               1,833
        Changes in Fair Value Risk Management Contracts
        Allocated to Regulated  Jurisdictions (e)                      351
                                                                    ------
        Total MTM Risk Management Contract Net
          Assets                                                    16,557
        Net Non-Trading Related Derivative
         Contracts                                                    (810)
                                                                    ------
        Net Fair Value of Risk Management and   Derivative
        Contracts  June 30, 2003                                   $15,747
                                                                   =======

     (a)"(Gain) Loss from Contracts Realized/Settled During the Period"
         includes realized gains from risk management contracts and related
         derivatives that settled during 2003 that were entered into prior
         to 2003.
     (b) The "Fair Value of New Contracts When Entered Into During the
         Period" represents the fair value of long-term contracts entered
         into with customers during 2003. The fair value is calculated as of
         the execution of the contract. Most of the fair value comes from
         longer term fixed price contracts with customers that seek to limit
         their risk against fluctuating energy prices. The contract prices
         are valued against market curves associated with the delivery
         location.
     (c) "Net Option Premiums Paid/(Received)" reflects the net option
         premiums paid/(received) as they relate to unexercised and
         unexpired option contracts that were entered into in 2003.
     (d)"Changes in Fair Value of Risk Management Contracts" represents the
         fair value change in the risk management portfolio due to market
         fluctuations during the current period. Market fluctuations are
         attributable to various factors such as supply/demand, weather,
         etc.
     (e)"Change in Fair Value of Risk Management Contracts Allocated to
         Regulated Jurisdictions" relates to the net gains (losses) of those
         contracts that are not reflected in the Statements of Income. These
         net gains (losses) are recorded as regulatory liabilities/assets
         for those subsidiaries that operate in regulated jurisdictions.


Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
 o The source of fair value used in determining the carrying amount of our
   total MTM asset or liability (external sources or modeled internally).
 o The maturity, by year, of our net assets/liabilities, giving an indication
   of when these MTM amounts will settle and generate cash.
<TABLE>
<CAPTION>
                                                  Maturity and Source of Fair Value of MTM
                                                   Risk Management Contract Net Assets
                                                Fair Value of Contracts as of June 30, 2003

                                              Remainder                                                        After
                                                2003         2004         2005        2006         2007        2007       Total
                                                ----         ----         ----        ----         ----        ----       -----
                                                                                (in thousands)
<S>                                             <C>         <C>           <C>        <C>          <C>          <C>        <C>
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                        $3,535      $4,021       $1,289      $1,144       $  365       $  -       $10,354
Prices Based on Models and Other
 Valuation Methods (b)                             229         506          563         977          988        2,940       6,203
                                                ------      ------       ------      ------       ------       ------     -------

    Total                                       $3,764      $4,527       $1,852      $2,121       $1,353       $2,940     $16,557
                                                ======      ======       ======      ======       ======       ======     =======
</TABLE>

(a)    "Prices Provided by Other External Sources - OTC Broker Quotes"
       reflects information obtained from over-the-counter brokers, industry
       services, or multiple-party on-line platforms.
(b)    "Prices Based on Models and Other Valuation Methods" if there is
       absence of pricing information from external sources, modeled
       information is derived using valuation models developed by the
       reporting entity, reflecting when appropriate, option pricing theory,
       discounted cash flow concepts, valuation adjustments, etc. and may
       require projection of prices for underlying commodities beyond the
       period that prices are available from third-party sources. In addition,
       where external pricing information or market liquidity are limited,
       such valuations are classified as modeled. The determination of the
       point at which a market is no longer liquid for placing it in the
       Modeled category varies by market.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).

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

<TABLE>
<CAPTION>
                                   Total Other Comprehensive Income (Loss) Activity
                                           Six Months Ended June 30, 2003

                                                        Domestic
                                                         Power          Interest Rate       Consolidated
                                                        --------        -------------       ------------
                                                                        (in thousands)
<S>                                                        <C>                  <C>               <C>
        Accumulated OCI, December 31, 2002                 $(103)               $425              $   322
        ----------------------------------
        Changes in Fair Value (a)                           (493)                 (1)                (494)
        Reclassifications from OCI to Net
         Income (b)                                           31                 (43)                 (12)
                                                           -----                ----              -------
        Accumulated OCI Derivative Gain (Loss)
        June 30, 2003                                      $(565)               $381                $(184)
                                                           =====                ====                =====
</TABLE>

(a)   "Changes in Fair Value" shows changes in the fair value of derivatives
      designated as hedging instruments in cash flow hedges during the
      reporting period not yet reclassified into net income, pending the
      hedged item's affecting net income. Amounts are reported net of related
      income taxes.
(b)   "Reclassifications from OCI to Net Income" represents gains or losses
      from derivatives used as hedging instruments in cash flow hedges that
      were reclassified into net income during the reporting period. Amounts
      are reported net of related income taxes above.

The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $298 thousand loss.

Credit Risk

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

VaR Associated with Energy Trading Contracts

The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
<TABLE>
<CAPTION>
                         June 30, 2003                                                   December 31, 2002
                         (in thousands)                                                   (in thousands)
           End        High       Average      Low                               End        High       Average    Low
           ---        ----       -------      ---                               ---        ----       -------    ---

<S>        <C>        <C>         <C>         <C>                              <C>        <C>           <C>      <C>
           $79        $536        $298        $79                              $333       $1,019        $364     $74


</TABLE>

<PAGE>
<TABLE>
<CAPTION>
                                                              KENTUCKY POWER COMPANY
                                                               STATEMENTS OF INCOME
                                                                   (UNAUDITED)

                                                                Three Months Ended June 30,             Six Months Ended June 30,
                                                                  2003                2002                2003               2002
                                                                  ----                ----                ----               ----
                                                                                           (in thousands)
OPERATING REVENUES:
<S>                                                            <C>                  <C>                <C>               <C>
    Electric Generation, Transmission and  Distribution        $ 84,296             $ 83,271           $188,255          $176,434
    Sales to AEP Affiliates                                      11,168                8,893             19,303            14,915
                                                               --------             --------           --------          --------

           TOTAL OPERATING REVENUES                              95,464               92,164            207,558           191,349
                                                               --------             --------           --------          --------

OPERATING EXPENSES:
    Fuel for Electric Generation                                 15,439               17,570             33,386            39,337
    Purchased Electricity from AEP Affiliates                    36,152               32,368             73,547            61,309
    Other Operation                                              11,695               12,619             23,832            24,970
    Maintenance                                                   7,161                8,078             13,926            12,627
    Depreciation and Amortization                                 9,248                8,269             17,960            16,526
    Taxes Other Than Income Taxes                                 2,077                2,368              4,442             4,503
    Income Taxes                                                  2,728                1,342              9,667             7,043
                                                               --------             --------           --------          --------

           TOTAL OPERATING EXPENSES                              84,500               82,614            176,760           166,315
                                                               --------             --------           --------          --------

OPERATING INCOME                                                 10,964                9,550             30,798            25,034

NONOPERATING INCOME (LOSS)                                         (550)               3,553             (2,965)            5,195

NONOPERATING EXPENSES (CREDITS)                                     110                 (576)               342                (6)

NONOPERATING INCOME TAX
 EXPENSE (CREDIT)                                                  (926)               1,920             (1,484)            1,730

INTEREST CHARGES                                                  7,135                6,513             13,859            13,013
                                                               --------             --------           --------          --------

INCOME BEFORE CUMULATIVE EFFECT
 OF ACCOUNTING CHANGE                                             4,095                5,246             15,116            15,492

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

NET INCOME                                                     $  4,095             $  5,246           $ 13,982          $ 15,492
                                                               ========             ========           ========          ========
</TABLE>

The common stock of KPCo is wholly owned by AEP.

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                                        KENTUCKY POWER COMPANY
                                STATEMENTS OF 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                                   $50,450       $158,750         $48,833           $(1,903)          $256,130
Common Stock Dividends                                                           (14,088)                             (14,088)
                                                                                                                     --------
                                                                                                                      242,042
                                                                                                                     --------
Comprehensive Income:
  Other Comprehensive Income,
   Net of Taxes:
    Unrealized Gain on Cash Flow Hedges                                                              1,445              1,445
  Net Income                                                                      15,492                               15,492
                                                                                                                     --------
     Total Comprehensive Income                                                                                        16,937
                                                  -------       --------         -------           -------           --------

JUNE 30, 2002                                     $50,450       $158,750         $50,237           $  (458)          $258,979
                                                  =======       ========         =======           =======           ========



JANUARY 1, 2003                                   $50,450       $208,750         $48,269           $(9,451)          $298,018
Common Stock Dividends                                                           (10,966)                             (10,966)
                                                                                                                     --------
                                                                                                                      287,052
                                                                                                                     --------
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow Hedges                                                               (506)              (506)
  Net Income                                                                      13,982                               13,982
                                                                                                                     --------
     Total Comprehensive Income                                                                                        13,476
                                                  -------       --------         -------           -------           --------

JUNE 30, 2003                                     $50,450       $208,750         $51,285          $ (9,957)          $300,528
                                                  =======       ========         =======          ========           ========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>
                                                           KENTUCKY POWER COMPANY
                                                               BALANCE SHEETS
                                                                (UNAUDITED)

                                                                                            June 30, 2003        December 31, 2002
                                                                                            -------------        -----------------
                                                                                                        (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                           <C>                      <C>
   Production                                                                                 $  415,289               $  275,121
   Transmission                                                                                  376,119                  373,639
   Distribution                                                                                  419,272                  414,281
   General                                                                                        66,532                   67,449
   Construction Work in Progress                                                                  60,128                  165,129
                                                                                              ----------               ----------
        Total Electric Utility Plant                                                           1,337,340                1,295,619
   Accumulated Depreciation and Amortization                                                     397,743                  397,304
                                                                                              ----------               ----------
          NET ELECTRIC UTILITY PLANT                                                             939,597                  898,315
                                                                                              ----------               ----------

OTHER PROPERTY AND INVESTMENTS                                                                     6,333                    6,904
                                                                                              ----------               ----------

LONG-TERM RISK MANAGEMENT ASSETS                                                                  23,502                   29,871
                                                                                              ----------               ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                       1,692                    2,304
   Accounts Receivable:
      Customers                                                                                   16,672                   22,044
      Affiliated Companies                                                                        14,730                   23,802
      Miscellaneous                                                                                4,916                    2,889
      Allowance for Uncollectible Accounts                                                          (974)                    (192)
   Fuel                                                                                           11,538                   10,817
   Materials and Supplies                                                                         18,078                   16,127
   Accrued Utility Revenues                                                                        6,435                    5,301
   Accrued Tax Benefit                                                                              -                       1,253
   Risk Management Assets                                                                         19,946                   24,320
   Prepayments and Other                                                                           2,954                    2,127
                                                                                              ----------               ----------
          TOTAL CURRENT ASSETS                                                                    95,987                  110,792
                                                                                              ----------               ----------

REGULATORY ASSETS                                                                                104,763                  101,976
                                                                                              ----------               ----------

DEFERRED CHARGES                                                                                  14,494                   16,818
                                                                                              ----------               ----------

          TOTAL ASSETS                                                                        $1,184,676               $1,164,676
                                                                                              ==========               ==========
</TABLE>

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




<PAGE>
<TABLE>
<CAPTION>
                                                       KENTUCKY POWER COMPANY
                                                           BALANCE SHEETS
                                                             (UNAUDITED)

                                                                                         June 30, 2003        December 31, 2002
                                                                                         -------------        -----------------
                                                                                                     (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                                                        <C>                    <C>
 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)                                                 (9,957)                (9,451)
 Retained Earnings                                                                             51,285                 48,269
                                                                                           ----------             ----------
        Total Common Shareowner's Equity                                                      300,528                298,018
 Long-term Debt                                                                               427,555                391,632
 Long-term Debt - Affiliated Companies                                                         60,000                 60,000
                                                                                           ----------             ----------

           TOTAL CAPITALIZATION                                                               788,083                749,650
                                                                                           ----------             ----------

OTHER NONCURRENT LIABILITIES                                                                   25,794                 27,319
                                                                                           ----------             ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year
     - Affiliated Companies                                                                      -                    15,000
   Advances from Affiliates                                                                    54,262                 23,386
   Accounts Payable:
      General                                                                                  25,083                 46,515
      Affiliated Companies                                                                     22,216                 44,035
   Customer Deposits                                                                           11,219                  8,048
   Interest Accrued                                                                             6,554                  6,471
   Taxes Accrued                                                                                4,922                   -
   Risk Management Liabilities                                                                 14,800                 17,803
   Other                                                                                       10,173                 14,322
                                                                                           ----------             ----------

           TOTAL CURRENT LIABILITIES                                                          149,229                175,580
                                                                                           ----------             ----------

DEFERRED INCOME TAXES                                                                         187,745                178,313
                                                                                           ----------             ----------

DEFERRED INVESTMENT TAX CREDITS                                                                 8,578                  9,165
                                                                                           ----------             ----------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                          12,901                 11,488
                                                                                           ----------             ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                    12,346                 13,161
                                                                                           ----------             ----------

COMMITMENTS AND CONTINGENCIES (Note 7)

           TOTAL CAPITALIZATION AND LIABILITIES                                            $1,184,676             $1,164,676
                                                                                           ==========             ==========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                               KENTUCKY POWER COMPANY
                                                              STATEMENTS OF CASH FLOWS
                                                                    (UNAUDITED)


                                                                                                    Six Months Ended June 30,
                                                                                                    2003                 2002
                                                                                                    ----                 ----
                                                                                                         (in thousands)

OPERATING ACTIVITIES:
<S>                                                                                              <C>                   <C>
   Net Income                                                                                    $ 13,982              $ 15,492
   Adjustments to Reconcile Net Income to Net Cash Flows
    From Operating Activities:
      Cumulative Effect of Accounting Change                                                        1,134                  -
      Depreciation and Amortization                                                                17,960                16,526
      Deferred Income Taxes                                                                         7,605                   965
      Deferred Investment Tax Credits                                                                (587)                 (591)
      Deferred Fuel Costs, net                                                                       (932)                2,430
      Mark-to-Market of Risk Management Contracts                                                   6,697                (4,479)
   Changes in Certain Assets and Liabilities:
      Accounts Receivable, net                                                                     13,199               (27,044)
      Fuel, Materials and Supplies                                                                 (2,672)               (6,481)
      Accrued Utility Revenues                                                                     (1,134)               (2,418)
      Accounts Payable                                                                            (43,251)               24,610
      Taxes Accrued                                                                                 6,175                   129
   Change in Other Assets                                                                          (2,360)               (1,416)
   Change in Other Liabilities                                                                      1,261                 6,355
                                                                                                 --------              --------
           Net Cash Flows From Operating Activities                                                17,077                24,078
                                                                                                 --------              --------

INVESTING ACTIVITIES:
   Construction Expenditures                                                                      (57,897)              (51,997)
   Proceeds from Sales of Property and Other                                                          298                  -
                                                                                                 --------              --------
           Net Cash Flow Used for Investing Activities                                            (57,599)              (51,997)
                                                                                                 --------              --------

FINANCING ACTIVITIES:
    Issuance of Long-term Debt                                                                     75,000                  -
    Issuance of Long-term Debt - Affiliated Companies                                                -                  123,843
    Retirement of Long-term Debt                                                                  (40,000)              (14,500)
    Retirement of Long-term Debt - Affiliated Companies                                           (15,000)                 -
    Change in Advances to/from Affiliates, net                                                     30,876               (68,365)
    Dividends Paid                                                                                (10,966)              (14,088)
                                                                                                 --------              --------
           Net Cash Flows From Financing Activities                                                39,910                26,890
                                                                                                 --------              --------

Net Decrease in Cash and Cash Equivalents                                                            (612)               (1,029)
Cash and Cash Equivalents at Beginning of Period                                                    2,304                 1,947
                                                                                                 --------              --------
Cash and Cash Equivalents at End of Period                                                       $  1,692              $    918
                                                                                                 ========              ========
</TABLE>

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $13,245,000 and
$13,692,000 in 2003 and 2002, respectively. Cash paid (received) for income
taxes was $(5,537,000) and $7,024,000 in 2003 and 2002, respectively. Noncash
acquisitions under capital leases were $22,000 in 2002.

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

                               OHIO POWER COMPANY
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations
---------------------

Net Income increased $130 million year-to-date including 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 $5
million year-to-date due primarily to increased Sales to AEP Affiliates. We, as
a member of the AEP Power Pool, share in the revenues and the costs of the AEP
Power Pool's wholesale sales to neighboring utilities and power marketing
transactions.

Operating Income

Operating Income increased $19 million for the second quarter and $34 million
year-to-date primarily due to the following:

o   Second quarter and year-to-date revenues from non-affiliated
    system sales increased $9 million and $26 million, respectively,
    while affiliated system sales increased $25 million and $42
    million, respectively. The overall increase in system sales for
    resale is the result of optimizing our generation capacity and
    selling our excess generated power due to the unexpected outages
    at the affiliate owned Cook Plant.
o   Other Operation expenses decreased $21 million for the second
    quarter and $19 million year-to-date primarily due to a $7 million
    pre-tax adjustment to the workers' compensation reserve related to
    the sale of coal companies coupled with reductions in employee
    salary and benefit expenses and office related expenses totaling
    $12 million.

The increase in Operating Income was partially offset by:

o   Second quarter retail revenues decreased $15 million due to milder weather
    during the second quarter 2003 and the effects of a weak economy.
o   Year-to-date Fuel for Electric Generation expense increased $16 million
    due to an increase of 7.7% in MWHs generated.
o   Second quarter and year-to-date expenses for Purchased Electricity from
    AEP Affiliates were $4 million and $13 million higher due to price and
    volume increases.
o   Second quarter and year-to-date Maintenance expenses increased $24 million
    and $30 million primarily due to increased boiler overhaul costs coupled
    with increased expense in maintaining overhead lines due to storm damage
    in southern Ohio.

Other Impacts on Earnings

Nonoperating Income decreased $14 million in the second quarter and $31 million
year-to-date primarily due to lower margins for power sold outside of AEP's
traditional marketing area reflecting reduced demand and AEP's plan to exit risk
management activities in areas outside of its traditional market area.

Nonoperating Expenses increased $3 million for the second quarter and $6 million
year-to-date as a result of an increase in expenses related to the Cook Coal
Terminal in both the quarter-to-date and year-to-date periods and a $2 million
loss recorded on the sale of our water heater rental program in the year-to-date
period.

The $7 million year-to-date decrease in Nonoperating Income Tax Expense was the
result of the overall decrease in income related to our risk management
activities.

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).

Financial Condition
-------------------

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                             Moody's       S&P         Fitch
                                             -------       ---         -----
          First Mortgage Bonds               A3            BBB         A-
          Senior Unsecured Debt              A3            BBB         BBB+

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.

Cash Flow

Cash flows for six months ended June 30, 2003 and 2002 were as follows:
<TABLE>
<CAPTION>

                                                                                   2003              2002
                                                                              --------------    --------------
                                                                                       (in thousands)
<S>                                                                             <C>                <C>
           Cash and cash equivalents at beginning of period                     $   5,285          $   8,848
           Cash flow from (used for):
             Operating activities                                                  74,842            239,758
             Investing activities                                                (114,485)          (157,797)
             Financing activities                                                  43,033            (83,937)
                                                                                ---------          ---------
           Net increase (decrease) in cash and cash equivalents                    3,390             (1,976)
                                                                                ---------          ---------

           Cash and cash equivalents at end of period                           $   8,675          $   6,872
                                                                                =========          =========
</TABLE>

Operating Activities

Cash flow from operating activities during the first half of 2003 decreased $165
million as they were adversely impacted primarily by significant reductions of
accounts payable balances partially associated with a wind down of risk
management activities in the current year.

Investing Activities

Cash flows used for investing activities were reduced in the current year
directly attributable to a $40 million decrease in construction expenditures.

Financing Activities

Cash flow from financing activities in the first of half of 2003 used $127
million less than the first half of 2002 primarily due to:

o  Retirement and restructuring of our long-term and short-term debt
   during 2003. We retired $300 million of Long-term Debt to Affiliated
   Companies and $275 million of Short-term Debt to Affiliated Companies with
   the proceeds of two Senior Unsecured Notes at $250 million each, as well
   as a $232 million increase in Advances from Affiliates.
o  Dividends paid on common stock increased $19 million from the prior period.

Financing Activity

In February 2003, we 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%. The proceeds from the issuances were used to repay long-term debt,
short-term debt and for other corporate purposes.

In July 2003, we issued $225 million of unsecured senior notes due 2014 at a
coupon of 4.85% and $225 million of unsecured senior notes due 2033 at a coupon
of 6.375%. See Note 12 for additional information related to financing activity.

Significant Factors
-------------------

Federal EPA Complaint and Notice of Violation

As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", OPCo and certain affiliated companies have been
involved in litigation since 1999 regarding generating plant emissions under the
Clean Air Act. Federal EPA and a number of states alleged OPCo, certain
affiliated companies 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

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.

We are 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 $524 million to $853 million. 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.

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets

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

             Roll-Forward of MTM Risk Management Contract Net Assets
                         Six Months Ended June 30, 2003

        Domestic Power
        --------------
                                                                 (in thousands)
        Beginning Balance December 31, 2002                         $94,106
        -----------------------------------
        (Gain) Loss from Contracts Realized/Settled
         During  the Period (a)                                     (39,181)
        Fair Value of New Contracts When Entered Into
        During the Period (b)                                          -
        Net Option Premiums Paid/(Received) (c)                         369
        Change in Fair Value Due to Valuation
         Methodology  Changes                                          -
        Effect of 98-10 Rescission                                   (4,159)
        Changes in Fair Value of Risk Management
         Contracts (d)                                               12,431
        Changes in Fair Value of Risk Management Contracts
        Allocated to Regulated Jurisdictions (e)                       -
                                                                     -------
        Total MTM Risk Management Contract Net
         Assets                                                      63,566
        Net Non-Trading Related Derivative
         Contracts                                                   (2,745)
                                                                    -------
        Net Fair Value of Risk Management and Derivative
        Contracts June 30, 2003                                     $60,821
                                                                    =======

        (a)"(Gain) Loss from Contracts Realized/Settled During the Period"
           includes realized gains from risk management contracts and related
           derivatives that settled during 2003 that were entered into prior to
           2003.
        (b) The "Fair Value of New Contracts When Entered Into During the
           Period" represents the fair value of long-term contracts entered into
           with customers during 2003. The fair value is calculated as of the
           execution of the contract. Most of the fair value comes from longer
           term fixed price contracts with customers that seek to limit their
           risk against fluctuating energy prices. The contract prices are
           valued against market curves associated with the delivery location.
        (c) "Net Option Premiums Paid/(Received)" reflects the net option
           premiums paid/(received) as they relate to unexercised and unexpired
           option contracts that were entered into in 2003.
        (d)"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.
        (e)"Change in Fair Value of Risk Management Contracts Allocated to
           Regulated Jurisdictions" relates to the net gains (losses) of those
           contracts that are not reflected in the Consolidated Statements of
           Income. These net gains (losses) are recorded as regulatory
           liabilities/assets for those subsidiaries that operate in regulated
           jurisdictions.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
 o The source of fair value used in determining the carrying amount of our
   total MTM asset or liability (external sources or modeled internally).
 o The maturity, by year, of our net assets/liabilities, giving an indication
   of when these MTM amounts will settle and generate cash.
<TABLE>
<CAPTION>
                                                       Maturity and Source of Fair Value of MTM
                                                        Risk Management Contract Net Assets
                                                      Fair Value of Contracts as of June 30, 2003

                                                 Remainder                                                      After
                                                   2003          2004        2005        2006         2007      2007        Total
                                                   ----          ----        ----        ----         ----      ----        -----
                                                                                      (in thousands)
<S>                                                <C>         <C>          <C>         <C>          <C>       <C>         <C>
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                           $17,123     $15,750      $4,418      $3,919       $1,252    $  -        $42,462
Prices Based on Models and Other
 Valuation Methods (b)                                 632       1,734       1,929       3,348        3,385     10,076      21,104
                                                   -------     -------      ------      ------       ------    -------     -------

    Total                                          $17,755     $17,484      $6,347      $7,267       $4,637    $10,076     $63,566
                                                   =======     =======      ======      ======       ======    =======     =======
</TABLE>

(a)     "Prices Provided by Other External Sources - OTC Broker Quotes"
         reflects information obtained from over-the-counter brokers, industry
         services, or multiple-party on-line platforms.
(b)     "Prices Based on Models and Other Valuation Methods" if there is
         absence of pricing information from external sources, modeled
         information is derived using valuation models developed by the
         reporting entity, reflecting when appropriate, option pricing theory,
         discounted cash flow concepts, valuation adjustments, etc. and may
         require projection of prices for underlying commodities beyond the
         period that prices are available from third-party sources. In addition,
         where external pricing information or market liquidity are limited,
         such valuations are classified as modeled. The determination of the
         point at which a market is no longer liquid for placing it in the
         Modeled category varies by market.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).

Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
<TABLE>
<CAPTION>
                               Total Other Comprehensive Income (Loss) Activity
                                      Six Months Ended June 30, 2003

                                                        Domestic           Foreign
                                                         Power            Currency         Consolidated
                                                        --------          --------         ------------
                                                                        (in thousands)
<S>                                                      <C>               <C>                  <C>
        Accumulated OCI, December 31, 2002               $  (354)          $(384)               $  (738)
        ----------------------------------
        Changes in Fair Value (a)                         (1,690)             -                  (1,690)
        Reclassifications from OCI to Net
         Income (b)                                          107               7                    114
                                                         -------           -----                -------
        Accumulated OCI Derivative Gain (Loss)
        June 30, 2003                                    $(1,937)          $(377)               $(2,314)
                                                         =======           =====                =======
</TABLE>

(a)      "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
(b)      "Reclassifications from OCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $1,331 thousand loss.

Credit Risk

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

VaR Associated with Energy Trading Contracts

The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
<TABLE>
<CAPTION>
                        June 30, 2003                                                           December 31, 2002
                        (in thousands)                                                            (in thousands)
           End        High       Average      Low                                         End        High     Average    Low
           ---        ----       -------      ---                                         ---        ----     -------    ---

<S>       <C>        <C>          <C>         <C>                                       <C>         <C>        <C>      <C>
          $270       $1,836       $1,022      $270                                      $1,150      $3,521     $1,259   $255

</TABLE>

<PAGE>
<TABLE>
<CAPTION>
                                                                 OHIO POWER COMPANY
                                                                STATEMENTS OF INCOME
                                                                    (UNAUDITED)

                                                                 Three Months Ended June 30,             Six Months Ended June 30,
                                                                  2003                2002                 2003             2002
                                                                  ----                ----                 ----             ----
                                                                                            (in thousands)
OPERATING REVENUES:
<S>                                                              <C>                 <C>               <C>               <C>
    Electric Generation, Transmission and  Distribution          $387,892            $395,972          $  838,779        $  806,990
    Sales to AEP Affiliates                                       151,494             125,393             291,238           235,027
                                                                 --------            --------          ----------        ----------

           TOTAL OPERATING REVENUES                               539,386             521,365           1,130,017         1,042,017
                                                                 --------            --------          ----------        ----------

OPERATING EXPENSES:
    Fuel for Electric Generation                                  153,446             149,097             307,094           291,433
    Purchased Electricity for Resale                               17,454              15,572              36,845            33,201
    Purchased Electricity from AEP Affiliates                      24,428              20,265              47,212            34,492
    Other Operation                                                84,641             105,975             177,622           196,089
    Maintenance                                                    53,411              29,957              88,868            58,945
    Depreciation and Amortization                                  60,223              61,176             121,775           123,797
    Taxes Other Than Income Taxes                                  39,613              43,292              86,768            89,131
    Income Taxes                                                   26,339              34,985              85,132            70,167
                                                                 --------            --------          ----------        ----------

           TOTAL OPERATING EXPENSES                               459,555             460,319             951,316           897,255
                                                                 --------            --------          ----------        ----------

OPERATING INCOME                                                   79,831              61,046             178,701           144,762
NONOPERATING INCOME                                                 4,594              18,975                 783            31,900
NONOPERATING EXPENSES                                               7,102               3,853              17,725            11,260
NONOPERATING INCOME TAX EXPENSE
 (CREDIT)                                                           1,564                 626              (3,092)            4,348
INTEREST CHARGES                                                   19,482              20,194              40,224            41,655
                                                                 --------            --------          ----------        ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES              56,277              55,348             124,627           119,399

CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX)                 -                   -                124,632              -
                                                                 --------            --------          ----------        ----------

NET INCOME                                                         56,277              55,348             249,259           119,399

PREFERRED STOCK DIVIDEND REQUIREMENTS                                 315                 315                 629               629
                                                               ----------          ----------          ----------        ----------

EARNINGS APPLICABLE TO COMMON STOCK                            $   55,962          $   55,033          $  248,630        $  118,770
                                                               ==========          ==========          ==========        ==========
</TABLE>

The common stock of OPCo is wholly owned by AEP.

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

<PAGE>
<TABLE>
<CAPTION>
                                                          OHIO POWER COMPANY
                                 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                                      $321,201       $462,483        $401,297          $   (196)        $1,184,785
Common Stock Dividends                                                               (65,164)                             (65,164)
Preferred Stock Dividends                                                               (629)                                (629)
                                                                                                                       ----------
                                                                                                                        1,118,992
                                                                                                                       ----------
Comprehensive Income:
  Other Comprehensive Income (Loss)
   Net of Taxes:
    Unrealized Gain on Cash Flow Hedges                                                                  1,769              1,769
  Net Income                                                                         119,399                              119,399
                                                                                                                       ----------
     Total Comprehensive Income                                                                                           121,168
                                                     --------       --------        --------          --------         ----------

JUNE 30, 2002                                        $321,201       $462,483        $454,903          $  1,573         $1,240,160
                                                     ========       ========        ========          ========         ==========



JANUARY 1, 2003                                      $321,201       $462,483        $522,316          $(72,886)        $1,233,114
Common Stock Dividends                                                               (83,867)                             (83,867)
Preferred Stock Dividends                                                               (629)                                (629)
                                                                                                                       ----------
                                                                                                                        1,148,618
                                                                                                                       ----------
Comprehensive Income:
  Other Comprehensive Income (Loss)
   Net of Taxes:
    Unrealized Loss on Cash Flow Hedges                                                                 (1,576)            (1,576)
    Minimum Pension Liability                                                                            5,624              5,624
  Net Income                                                                         249,259                              249,259
                                                                                                                       ----------
     Total Comprehensive Income                                                                                           253,307
                                                     --------       --------        --------          --------         ----------

JUNE 30, 2003                                        $321,201       $462,483        $687,079          $(68,838)        $1,401,925
                                                     ========       ========        ========          ========         ==========
</TABLE>

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                                                 OHIO POWER COMPANY
                                                                   BALANCE SHEETS
                                                                     (UNAUDITED)

                                                                                              June 30, 2003     December 31, 2002
                                                                                              -------------     -----------------
                                                                                                       (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                             <C>                    <C>
   Production                                                                                   $3,217,096             $3,116,825
   Transmission                                                                                    902,897                905,829
   Distribution                                                                                  1,133,401              1,114,600
   General                                                                                         228,894                260,153
   Construction Work in Progress                                                                   259,299                288,419
                                                                                                ----------             ----------
        Total Electric Utility Plant                                                             5,741,587              5,685,826
   Accumulated Depreciation and Amortization                                                     2,354,453              2,566,828
                                                                                                ----------             ----------
          NET ELECTRIC UTILITY PLANT                                                             3,387,134              3,118,998
                                                                                                ----------             ----------

OTHER PROPERTY AND INVESTMENTS                                                                      55,453                 61,686
                                                                                                ----------             ----------

LONG-TERM RISK MANAGEMENT ASSETS                                                                    80,541                103,230
                                                                                                ----------             ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                         8,675                  5,285
   Accounts Receivable:
      Customers                                                                                     77,238                 95,100
      Affiliated Companies                                                                         136,697                124,244
      Miscellaneous                                                                                 26,438                 19,281
      Allowance for Uncollectible Accounts                                                            (921)                  (909)
   Fuel                                                                                             86,886                 87,409
   Materials and Supplies                                                                           88,421                 85,379
   Risk Management Assets                                                                           75,398                 92,108
   Prepayments and Other                                                                            32,625                 12,083
                                                                                                ----------             ----------
          TOTAL CURRENT ASSETS                                                                     531,457                519,980
                                                                                                ----------             ----------

REGULATORY ASSETS                                                                                  530,805                568,641
                                                                                                ----------             ----------

DEFERRED CHARGES AND OTHER ASSETS                                                                  105,651                 84,497
                                                                                                ----------             ----------

          TOTAL ASSETS                                                                          $4,691,041             $4,457,032
                                                                                                ==========             ==========
</TABLE>


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


<PAGE>
<TABLE>
<CAPTION>
                                                              OHIO POWER COMPANY
                                                                BALANCE SHEETS
                                                                 (UNAUDITED)

                                                                                      June 30, 2003           December 31, 2002
                                                                                      -------------           -----------------
                                                                                                  (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                                                     <C>                     <C>
   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)                                           (68,838)                (72,886)
   Retained Earnings                                                                       687,079                 522,316
                                                                                        ----------              ----------
        Total Common Shareholder's Equity                                                1,401,925               1,233,114
   Cumulative Preferred Stock:
      Not Subject to Mandatory Redemption                                                   16,646                  16,648
      Subject to Mandatory Redemption                                                        8,350                   8,850
   Long-term Debt                                                                        1,175,839                 677,649
   Long-term Debt - Affiliated Companies                                                      -                    240,000
                                                                                        ----------              ----------

           TOTAL CAPITALIZATION                                                          2,602,760               2,176,261
                                                                                        ----------              ----------

OTHER NONCURRENT LIABILITIES                                                               222,900                 227,689
                                                                                        ----------              ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year - General                                             59,815                  89,665
   Long-term Debt Due Within One Year - Affiliated Companies                                  -                     60,000
   Short-term Debt - Affiliates                                                               -                    275,000
   Advances from Affiliates                                                                362,860                 129,979
   Accounts Payable - General                                                               97,986                 170,563
   Accounts Payable - Affiliated Companies                                                  64,821                 145,718
   Customer Deposits                                                                        22,493                  12,969
   Taxes Accrued                                                                           128,075                 111,778
   Interest Accrued                                                                         28,914                  18,809
   Obligations Under Capital Leases                                                          9,482                  14,360
   Risk Management Liabilities                                                              50,905                  61,839
   Other                                                                                    55,910                  80,608
                                                                                        ----------              ----------

           TOTAL CURRENT LIABILITIES                                                       881,261               1,171,288
                                                                                        ----------              ----------

DEFERRED INCOME TAXES                                                                      880,981                 794,387
                                                                                        ----------              ----------

DEFERRED INVESTMENT TAX CREDITS                                                             17,223                  18,748
                                                                                        ----------              ----------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                       44,213                  39,702
                                                                                        ----------              ----------

DEFERRED CREDITS                                                                            41,703                  28,957
                                                                                        ----------              ----------

COMMITMENTS AND CONTINGENCIES (Note 7)

       TOTAL CAPITALIZATION AND LIABILITIES                                             $4,691,041              $4,457,032
                                                                                        ==========              ==========
</TABLE>

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                                           OHIO POWER COMPANY
                                                        STATEMENTS OF CASH FLOWS
                                                              (UNAUDITED)

                                                                                                Six Months Ended June 30,
                                                                                                  2003             2002
                                                                                                  ----             ----
                                                                                                      (in thousands)

OPERATING ACTIVITIES:
<S>                                                                                            <C>                  <C>
   Net Income                                                                                  $249,259             $119,399
   Adjustments to Reconcile Net Income to Net Cash Flows
    From Operating Activities:
      Cumulative Effect of Accounting Changes                                                  (124,632)                -
      Depreciation and Amortization                                                             121,775              123,797
      Deferred Income Taxes                                                                         372              (18,653)
      Mark to Market of Risk Management Contracts                                                26,381              (24,493)
   Changes in Certain Assets and Liabilities:
      Accounts Receivable, net                                                                   (1,736)             (66,769)
      Fuel, Materials and Supplies                                                               (2,519)               4,471
      Accrued Utility Revenues                                                                    5,995               (5,276)
      Prepayments and Other                                                                     (20,542)             (15,759)
      Accounts Payable                                                                         (153,474)              95,017
      Customer Deposits                                                                           9,524                3,585
      Taxes Accrued                                                                              16,297               14,274
      Interest Accrued                                                                           10,105                4,286
      Deferred Property Taxes                                                                    29,337               30,046
   Change in Other Assets                                                                       (47,741)               6,667
   Change in Other Liabilities                                                                  (43,559)             (30,834)
                                                                                              ---------            ---------
           Net Cash Flows From Operating Activities                                              74,842              239,758
                                                                                              ---------            ---------

INVESTING ACTIVITIES:
   Construction Expenditures                                                                   (117,761)            (158,080)
   Proceeds from Sale of Property and Other                                                       3,276                  283
                                                                                              ---------            ---------
           Net Cash Flows Used For Investing Activities                                        (114,485)            (157,797)
                                                                                              ---------            ---------

FINANCING ACTIVITIES:
   Issuance of Long-term Debt                                                                   500,000                 -
   Change in Advances to/from Affiliates, net                                                   232,881             (163,144)
   Change in Short-term Debt - Affiliates                                                      (275,000)             150,000
   Retirement of Long-term Debt                                                                 (29,850)              (5,000)
   Retirement of Long-term Debt - Affiliated                                                   (300,000)                -
   Retirement of Cumulative Preferred Stock                                                        (502)                -
   Dividends Paid on Common Stock                                                               (83,867)             (65,164)
   Dividends Paid on Cumulative Preferred Stock                                                    (629)                (629)
                                                                                              ---------            ---------
           Net Cash Flows From (Used For) Financing Activities                                   43,033              (83,937)
                                                                                              ---------            ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                              3,390               (1,976)
Cash and Cash Equivalents at Beginning of Period                                                  5,285                8,848
                                                                                              ---------            ---------
Cash and Cash Equivalents at End of Period                                                    $   8,675            $   6,872
                                                                                              =========            =========
</TABLE>

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $29,304,000 and
$36,585,000 and for income taxes was $26,455,000 and $29,187,000 in 2003 and
2002, respectively. Noncash acquisitions under capital leases were $98,000 in
2002.

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

<PAGE>

                PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
            MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations
---------------------

Net Income increased year-to-date and for the second quarter by $9 million and
$6 million, respectively. Large swings occurred in revenues, fuel and purchased
power due to fuel price market volatility (primarily natural gas), however,
income is generally not significantly affected due to the functioning of the
fuel adjustment clause in Oklahoma.

Operating Income

Operating Income increased $13 million year-to-date and $9 million for the
second quarter primarily due to the following:

o  Increased wholesale margins year-to-date of $2 million and for the second
   quarter of $1 million.
o  Increased other customer service revenues of $3 million year-to-date and $1
   million for the second quarter due to increased rents and service work for
   customers.
o  Decreased Other Operation and Maintenance expenses of $2 million
   year-to-date and $2 million for the second quarter due in large part to the
   absence in 2003 of storm damage that occurred in the first quarter 2002 and
   reduced transmission and power plant maintenance during the second quarter
   2003.
o  Decreased Income Taxes of $1 million  year-to-date and $3 million for the
   second quarter due to state income tax accrual adjustments offset by
   increases in pre-tax operating book income.

The increase in Operating Income was partially offset by:

o  Increased Taxes Other Than Income Taxes of $2 million year-to-date due
   primarily to increased property value assessments and franchise taxes.

Other Impacts on Earnings

Nonoperating Income decreased approximately $1 million primarily due to a gain
on the disposition of an investment in 2002. No such transaction occurred in the
current year.

Interest Charges increased $5 million year-to-date and $1 million for the second
quarter as a result of replacing floating rate short-term debt with longer term
fixed rate unsecured debt .

Financial Condition
-------------------

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                             Moody's       S&P         Fitch
                                             -------       ---         -----
          First Mortgage Bonds               A3            BBB         A
          Senior Unsecured Debt              Baa1          BBB         A-

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of our rating for unsecured debt from A2 to Baa1. The completion of this review
was a culmination of ratings action started during 2002. In March 2003, S&P
lowered AEP and its subsidiaries' senior unsecured ratings from BBB+ to BBB
along with the first mortgage bonds of AEP subsidiaries.

Financing Activity

Retired $35 million of first mortgage bonds on April 1, 2003 with coupon of
6.25% due 2003, and received a $50 million capital contribution from our parent
company. See Note 12 for additional information related to financing activity.

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets

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

             Roll-Forward of MTM Risk Management Contract Net Assets
                         Six Months Ended June 30, 2003

        Domestic Power
        --------------
                                                                (in  thousands)
        Beginning Balance December 31, 2002                         $ 3,545
        -----------------------------------
        (Gain) Loss from Contracts Realized/Settled
         During  the Period (a)                                         220
        Fair Value of New Contracts When Entered Into
        During the Period (b)                                          -
        Net Option Premiums Paid/(Received) (c)                        -
        Change in Fair Value Due to Valuation
         Methodology  Changes                                          -
        Effect of 98-10 Rescission                                     -
        Changes in Fair Value of Risk Management
         Contracts (d)                                                 -
        Changes in Fair Value of Risk Management Contracts
        Allocated to Regulated  Jurisdictions (e)                    12,120
                                                                    -------
        Total MTM Risk Management Contract Net
         Assets                                                      15,885
        Net Non-Trading Related Derivative
         Contracts                                                   (1,417)
                                                                    -------
        Net Fair Value of Risk Management and Derivative
        Contracts June 30, 2003                                     $14,468
                                                                    =======

   (a)"(Gain) Loss from Contracts Realized/Settled During the Period"
       includes realized gains from risk management contracts and related
       derivatives that settled during 2003 that were entered into prior to
       2003.
   (b) The "Fair Value of New Contracts When Entered Into During the
       Period" represents the fair value of long-term contracts entered
       into with customers during 2003. The fair value is calculated as of
       the execution of the contract. Most of the fair value comes from
       longer term fixed price contracts with customers that seek to limit
       their risk against fluctuating energy prices. The contract prices
       are valued against market curves associated with the delivery
       location.
   (c) "Net Option Premiums Paid/(Received)" reflects the net option
       premiums paid/(received) as they relate to unexercised and unexpired
       option contracts that were entered into in 2003.
   (d)"Changes in Fair Value of Risk Management Contracts" represents the
       fair value change in the risk management portfolio due to market
       fluctuations during the current period. Market fluctuations are
       attributable to various factors such as supply/demand, weather, etc.
   (e)"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.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
 o The source of fair value used in determining the carrying amount of our
   total MTM asset or liability (external sources or modeled internally).
 o The maturity, by year, of our net assets/liabilities, giving an indication
   of when these MTM amounts will settle and generate cash.
<TABLE>
<CAPTION>
                                                    Maturity and Source of Fair Value of MTM
                                                       Risk Management Contract Net Assets
                                                   Fair Value of Contracts as of June 30, 2003

                                               Remainder                                                 After
                                                  2003       2004           2005        2006      2007    2007     Total
                                                  ----       ----           ----        ----      ----    ----     -----
                                                                                 (in thousands)
<S>                                                <C>        <C>          <C>         <C>       <C>       <C>      <C>
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                           $3,430     $3,724       $1,251      $1,109    $  354    $ -      $ 9,868
Prices Based on Models and Other
 Valuation Methods (b)                                222        491          546         948       958     2,852     6,017
                                                   ------     ------       ------      ------    ------    ------   -------

    Total                                          $3,652     $4,215       $1,797      $2,057    $1,312    $2,852   $15,885
                                                   ======     ======       ======      ======    ======    ======   =======
</TABLE>

(a)      "Prices Provided by Other External Sources - OTC Broker Quotes reflects
         information obtained from over-the-counter brokers, industry services,
         or multiple-party on-line platforms.
     (b) "Prices Based on Models and Other Valuation Methods" if there is
         absence of pricing information from external sources, modeled
         information is derived using valuation models developed by the
         reporting entity, reflecting when appropriate, option pricing theory,
         discounted cash flow concepts, valuation adjustments, etc. and may
         require projection of prices for underlying commodities beyond the
         period that prices are available from third-party sources. In addition,
         where external pricing information or market liquidity are limited,
         such valuations are classified as modeled. The determination of the
         point at which a market is no longer liquid for placing it in the
         Modeled category varies by market.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll off of hedges).

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.

                Total Other Comprehensive Income (Loss) Activity
                         Six Months Ended June 30, 2003

                                                         Domestic
                                                           Power
                                                           -----
                                                      (in thousands)
        Accumulated OCI, December 31, 2002                 $ (42)
        ----------------------------------
        Changes in Fair Value (a)                           (903)
        Reclassifications from OCI to Net
         Income (b)                                           24
                                                           -----
        Accumulated OCI Derivative Gain  (Loss) June
        30, 2003                                           $(921)
                                                           =====

(a)      "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
(b)      "Reclassifications from OCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $626 thousand loss.

Credit Risk

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

VaR Associated with Energy Trading Contracts

The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
<TABLE>
<CAPTION>
                       June 30, 2003                                                               December 31, 2002
                       (in thousands)                                                                (in thousands)
           End        High       Average      Low                                         End        High       Average    Low
           ---        ----       -------      ---                                         ---        ----       -------    ---

<S>       <C>         <C>          <C>        <C>                                         <C>        <C>          <C>      <C>
          $128        $873         $486       $128                                        $136       $415         $148     $30
</TABLE>

<PAGE>
<TABLE>
<CAPTION>
                                              PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
                                                       CONSOLIDATED STATEMENTS OF INCOME
                                                                  (UNAUDITED)

                                                                    Three Months Ended June 30,           Six Months Ended June 30,
                                                                    2003                2002              2003                2002
                                                                    ----                ----              ----                ----
                                                                                           (in thousands)
OPERATING REVENUES:
<S>                                                              <C>                <C>                <C>               <C>
    Electric Generation, Transmission and  Distribution          $267,213           $152,168           $ 505,480         $ 299,060
    Sales to AEP Affiliates                                        10,023              6,162              14,418             8,256
                                                                 --------           --------           ---------         ---------
           TOTAL OPERATING REVENUES                               277,236            158,330             519,898           307,316
                                                                 --------           --------           ---------         ---------

OPERATING EXPENSES:
    Fuel for Electric Generation                                  135,395             33,772             238,569            91,869
    Purchased Electricity for Resale                                6,863             10,364              19,354             8,020
    Purchased Electricity from AEP  Affiliates                     28,276             12,073              70,383            28,918
    Other Operation                                                31,684             34,249              63,302            60,888
    Maintenance                                                    12,366             11,886              21,760            26,055
    Depreciation and Amortization                                  21,359             21,061              42,853            41,977
    Taxes Other Than Income Taxes                                   8,439              8,083              18,085            15,931
    Income Taxes                                                    4,139              6,641               3,731             5,047
                                                                 --------           --------           ---------         ---------
           TOTAL OPERATING EXPENSES                               248,521            138,129             478,037           278,705
                                                                 --------           --------           ---------         ---------

OPERATING INCOME                                                   28,715             20,201              41,861            28,611

NONOPERATING INCOME                                                    72              1,223                 722             1,329

NONOPERATING EXPENSE (CREDIT)                                        (276)                69                 163               664

NONOPERATING INCOME TAX EXPENSE (CREDIT)                             (155)              (100)               (355)             (241)

INTEREST CHARGES                                                   11,291              9,835              24,157            19,545
                                                                 --------           --------           ---------         ---------

NET INCOME                                                         17,927             11,620              18,618             9,972

PREFERRED STOCK DIVIDEND REQUIREMENTS                                 53                 53                 106               106
                                                                 --------           --------           ---------         ---------

EARNINGS APPLICABLE TO COMMON STOCK                             $ 17,874           $ 11,567           $  18,512         $   9,866
                                                                 ========           ========           =========         =========
</TABLE>

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

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

<PAGE>
<TABLE>
<CAPTION>
                                            PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
                          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                                    $157,230       $180,016            $142,994         $  -            $480,240
Common Stock Dividends                                                                 (44,911)                         (44,911)
Preferred Stock Dividends                                                                 (106)                            (106)
                                                                                                                       --------
                                                                                                                        435,223
                                                                                                                       --------
Comprehensive Income:
  Other Comprehensive Income                                                                                200             200
  Net Income                                                                             9,972                            9,972
                                                                                                                       --------
     Total Comprehensive Income                                                                                          10,172
                                                   --------       --------            --------          -------        --------

JUNE 30, 2002                                      $157,230       $180,016            $107,949         $    200        $445,395
                                                   ========       ========            ========         ========        ========



JANUARY 1, 2003                                    $157,230       $180,016            $116,474         $(54,473)       $399,247
Capital Contribution from Parent                                    50,000                                               50,000
Common Stock Dividends                                                                  (7,500)                          (7,500)
Preferred Stock Dividends                                                                 (106)                            (106)
Distribution of Investment in AEMT, Inc.
 Preferred Shares to Parent                                                               (548)                            (548)
                                                                                                                       --------
                                                                                                                        441,093
                                                                                                                       --------
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Minimum Pension Liability                                                                               (58)            (58)
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                         (879)           (879)
  Net Income                                                                            18,618                           18,618
                                                                                                                       --------
     Total Comprehensive Income                                                                                          17,681
                                                   --------       --------            --------         --------        --------

JUNE 30, 2003                                      $157,230       $230,016            $126,938         $(55,410)       $458,774
                                                   ========       ========            ========         ========        ========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>
                                              PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
                                                           CONSOLIDATED BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                              June 30, 2003      December 31, 2002
                                                                                              -------------      -----------------
                                                                                                         (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                             <C>                     <C>
  Production                                                                                    $1,061,688              $1,040,520
  Transmission                                                                                     434,390                 432,846
  Distribution                                                                                   1,006,691                 990,947
  General                                                                                          190,203                 206,747
  Construction Work in Progress                                                                     67,107                  88,444
                                                                                                ----------              ----------
      Total Electric Utility Plant                                                               2,760,079               2,759,504
  Accumulated Depreciation and Amortization                                                      1,244,909               1,239,855
                                                                                                ----------              ----------
          NET ELECTRIC UTILITY PLANT                                                             1,515,170               1,519,649
                                                                                                ----------              ----------

OTHER PROPERTY AND INVESTMENTS                                                                       4,827                   5,383
                                                                                                ----------              ----------

LONG-TERM RISK MANAGEMENT ASSETS                                                                    15,154                   4,481
                                                                                                ----------              ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                         18,573                  16,774
  Accounts Receivable:
   Customers                                                                                        37,761                  31,687
   Affiliated Companies                                                                             13,577                  14,139
   Allowance for Uncollectible Accounts                                                                (41)                    (84)
  Fuel Inventory                                                                                    19,101                  19,973
  Materials and Supplies                                                                            37,379                  37,375
  Under-recovered Fuel Costs                                                                        64,820                  76,470
  Risk Management Assets                                                                            16,360                   3,841
  Prepayments and Other                                                                              3,103                   2,735
                                                                                                ----------              ----------
          TOTAL CURRENT ASSETS                                                                     210,633                 202,910
                                                                                                ----------              ----------

REGULATORY ASSETS                                                                                   26,221                  26,150
                                                                                                ----------              ----------

DEFERRED CHARGES                                                                                    40,554                  18,117
                                                                                                ----------              ----------

                    TOTAL ASSETS                                                                $1,812,559              $1,776,690
                                                                                                ==========              ==========
</TABLE>


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

<PAGE>
<TABLE>
<CAPTION>
                                         PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
                                                    CONSOLIDATED BALANCE SHEETS
                                                            (UNAUDITED)

                                                                                     June 30, 2003            December 31, 2002
                                                                                     -------------            -----------------
                                                                                                (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                                                     <C>                      <C>
  Common Stock - $15 Par Value:
    Authorized Shares: 11,000,000
    Issued Shares: 10,482,000
    Outstanding Shares: 9,013,000                                                       $  157,230               $  157,230
  Paid-in Capital                                                                          230,016                  180,016
  Accumulated Other Comprehensive Income (Loss)                                            (55,410)                 (54,473)
  Retained Earnings                                                                        126,938                  116,474
                                                                                        ----------               ----------
    Total Common Shareholder's Equity                                                      458,774                  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                                                                             445,576                  445,437
                                                                                        ----------               ----------

          TOTAL CAPITALIZATION                                                             984,617                  924,951
                                                                                        ----------               ----------

OTHER NONCURRENT LIABILITIES                                                                55,324                   54,761
                                                                                        ----------               ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                                        65,000                  100,000
  Advances from Affiliates                                                                  68,555                   86,105
  Accounts Payable - General                                                                74,609                   61,169
  Accounts Payable - Affiliated Companies                                                   65,898                   78,076
  Customer Deposits                                                                         24,678                   21,789
  Taxes Accrued                                                                             12,634                    6,854
  Interest Accrued                                                                           5,403                    6,979
  Risk Management Liabilities                                                               11,065                    3,260
  Other                                                                                     17,901                   24,957
                                                                                        ----------               ----------

          TOTAL CURRENT LIABILITIES                                                        345,743                  389,189
                                                                                        ----------               ----------

DEFERRED INCOME TAXES                                                                      353,509                  341,396
                                                                                        ----------               ----------

DEFERRED INVESTMENT TAX CREDITS                                                             31,306                   32,201
                                                                                        ----------               ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                 36,079                   32,611
                                                                                        ----------               ----------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                        5,981                    1,581
                                                                                        ----------               ----------

COMMITMENTS AND CONTINGENCIES (Note 7)

                    TOTAL CAPITALIZATION AND LIABILITIES                                $1,812,559               $1,776,690
                                                                                        ==========               ==========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>
                                              PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
                                                    CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                 (UNAUDITED)

                                                                                           Six Months Ended June 30,
                                                                                        2003                        2002
                                                                                        ----                        ----
                                                                                                 (in thousands)

OPERATING ACTIVITIES:
<S>                                                                                    <C>                       <C>
   Net Income                                                                          $  18,618                 $  9,972
   Adjustments to Reconcile Net Income to Net Cash Flows
    From (Used For) Operating Activities:
      Depreciation and Amortization                                                       42,853                   41,977
      Deferred Income Taxes                                                               10,940                   21,559
      Deferred Investment Tax Credits                                                       (895)                    (895)
   Changes in Certain Assets and Liabilities:
      Accounts Receivable, net                                                            (5,555)                 (23,952)
      Fuel, Materials and Supplies                                                           868                   (3,226)
      Accounts Payable                                                                     1,262                   25,818
      Taxes Accrued                                                                        5,780                   (2,188)
      Fuel Recovery                                                                       11,650                  (53,156)
      Deferred Property Taxes                                                            (16,478)                 (16,184)
   Changes in Other Assets                                                                (9,551)                  (2,968)
   Changes in Other Liabilities                                                          (13,004)                  (4,387)
                                                                                        --------                 --------
           Net Cash Flows From (Used For) Operating Activities                            46,488                   (7,630)
                                                                                        --------                 --------

INVESTING ACTIVITIES:
  Construction Expenditures                                                              (34,660)                 (35,095)
  Other                                                                                      127                     (963)
                                                                                        --------                 --------
           Net Cash Flows Used For Investing Activities                                  (34,533)                 (36,058)
                                                                                        --------                 --------

FINANCING ACTIVITIES:
  Capital Contributions from Parent                                                       50,000                     -
  Change in Advances to/from Affiliates, net                                             (17,550)                  89,863
  Retirement of Long-term Debt                                                           (35,000)                    -
  Dividends Paid on Common Stock                                                          (7,500)                 (44,911)
  Dividends Paid on Cumulative Preferred Stock                                              (106)                    (106)
                                                                                        --------                 --------
           Net Cash Flows From (Used For) Financing Activities                           (10,156)                  44,846
                                                                                        --------                 --------

Net Increase in Cash and Cash Equivalents                                                  1,799                    1,158
Cash and Cash Equivalents at Beginning of Period                                          16,774                    5,795
                                                                                        --------                 --------
Cash and Cash Equivalents at End of Period                                              $ 18,573                 $  6,953
                                                                                        ========                 ========

</TABLE>

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $24,107,000 and
$17,870,000 and for income taxes was $8,975,000 and $2,575,000 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 in 2003.

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


<PAGE>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations
---------------------

Net Income increased $13 million year-to-date due in large part to the adoption
of SFAS 143, which resulted in a Cumulative Effect of Accounting Change of $9
million in the first quarter. Net Income for the second quarter increased $2
million due to increased wholesale margins and gains in risk management
activities. Although large swings occurred in revenues, fuel and purchased
power, due to fuel price market volatility (primarily natural gas), income was
generally not affected due to the functioning of fuel adjustment clauses.

Operating Income

Operating Income increased by $8 million year-to-date and $4 million for the
quarter primarily due to the following:

o   Increased wholesale margins both year-to-date and for the quarter.
o   Increased gains in risk management activities of $9 million year-to-date
    and $5 million for the quarter.
o   Other Operation  expense  decreased $9 million  year-to-date and
    $7 million for the quarter primarily due to SWEPCo's ability to defer a
    portion of fuel expense in the state of Louisiana.
o   Maintenance decreased $1 million year-to-date and $2 million for the
    quarter due to reduced scheduled power plant maintenance.

The increase in Operating Income was partially offset by:

o   Taxes Other Than Income Taxes increased year-to-date by $2 million due to
    increased property taxes resulting from adjustments for revised tax
    valuations.
o   Income Taxes increased for both year-to-date and for the quarter due to an
    increase in pre-tax operating book income. The quarter results are offset
    slightly by state income tax accrual adjustments.

Other Impacts on Earnings

Interest Charges increased $3 million year-to-date and $1 million for the
quarter primarily due to higher overall levels of outstanding debt and higher
average interest rates as floating rate debt was replaced with unsecured fixed
rate debt.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to the one-time, after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Notes 2 and 3).

Financial Condition
-------------------

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                            Moody's       S&P         Fitch
                                            -------       ---         -----
         First Mortgage Bonds               A3            BBB         A
         Senior Unsecured Debt              Baa1          BBB         A-

  In February 2003, Moody's Investors Service (Moody's) completed their review
  of AEP and its rated subsidiaries. The results of that review included a
  downgrade of our rating for unsecured debt from A2 to Baa1. The completion of
  this review was a culmination of ratings action started during 2002. In March
  2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+
  to BBB along with the first mortgage bonds of AEP subsidiaries.

Cash Flow

Cash flows for six months ended June 30, 2003 and 2002 were as follows:
<TABLE>
<CAPTION>

                                                                                   2003              2002
                                                                              --------------    --------------
                                                                                      (in thousands)
<S>                                                                             <C>                <C>
           Cash and cash equivalents at beginning of period                     $  2,069           $  5,415
           Cash flows from (used for):
             Operating activities                                                113,291             88,594
             Investing activities                                                (62,469)           (35,979)
             Financing activities                                                (42,391)           (42,170)
                                                                                ---------          ---------
           Net increase in cash and cash equivalents                               8,431             10,445
                                                                                ---------          ---------

           Cash and cash equivalents at end of period                           $ 10,500           $ 15,860
                                                                                =========          =========
</TABLE>


Operating Activities

Cash flows from operating activities increased $25 million in the first six
months of 2003 compared to the first six months of 2002 primarily due to a
build-up of fuel inventory during 2002.

Investing Activities

Cash spent on investing activities increased $26 million in comparison to the
prior year. Investment expenditures of $46 million in the current year were
related to projects for improved transmission and distribution service
reliability.

Financing Activities

Cash flows used for financing activities in the first half of 2003 were
comparable to the first half of 2002. During the first quarter of 2003 we
retired $55 million of first mortgage bonds at maturity. In April 2003, we
issued $100 million of senior unsecured debt due 2015 at a coupon of 5.375%. In
May 2003, our mining subsidiary issued $44 million of notes due in 2011 at a
coupon of 4.47%. See Note 12 for additional information related to financing
activity.

Significant Factors
-------------------

NOx Reductions

The Texas Commission on Environmental Quality adopted rules requiring
significant reductions in NOx emissions from utility sources, including SWEPCo.
Our compliance date is May 2005. We are installing non-selective catalytic
reduction 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 of approximately $35 million. The actual cost
to comply could be significantly different than the estimate 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.

Critical Accounting Policies

See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks

Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets

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

               Roll-Forward of MTM Risk Management Contract Net Assets
                          Six Months Ended June 30, 2003

Domestic Power
--------------                                                    (in thousands)
Beginning Balance December 31, 2002                                   $ 4,050
-----------------------------------
(Gain) Loss from Contracts Realized/Settled  During  the
 Period (a)                                                              (218)
Fair Value of New Contracts When Entered Into During the
 Period (b)                                                              -
Net Option Premiums Paid/(Received) (c)                                  -
Change in Fair Value Due to Valuation
 Methodology  Changes                                                    -
Effect of 98-10 Rescission                                                151
Changes in Fair Value of Risk Management
 Contracts (d)                                                          5,012
Changes in Fair Value of Risk Management Contracts
 Allocated to Regulated Jurisdictions (e)                               9,151
                                                                      -------
Total MTM Risk Management Contract Net
 Assets                                                                18,146
Net Non-Trading Related Derivative
 Contracts                                                             (1,618)
                                                                      -------
Net Fair Value of Risk Management and  Derivative
 Contracts June 30, 2003                                              $16,528
                                                                      =======

  (a)"(Gain) Loss from Contracts Realized/Settled During the Period"
      includes realized gains from risk management contracts and related
      derivatives that settled during 2003 that were entered into prior
      to 2003.
  (b) The "Fair Value of New Contracts When Entered Into During the
      Period" represents the fair value of long-term contracts entered
      into with customers during 2003. The fair value is calculated as of
      the execution of the contract. Most of the fair value comes from
      longer term fixed price contracts with customers that seek to limit
      their risk against fluctuating energy prices. The contract prices
      are valued against market curves associated with the delivery
      location.
  (c) "Net Option Premiums Paid/(Received)" reflects the net option
      premiums paid/(received) as they relate to unexercised and
      unexpired option contracts that were entered into in 2003.
  (d)"Changes in Fair Value of Risk Management Contracts" represents the
      fair value change in the risk management portfolio due to market
      fluctuations during the current period. Market fluctuations are
      attributable to various factors such as supply/demand, weather,
      etc.
  (e)"Change in Fair Value of Risk Management Contracts Allocated to
      Regulated Jurisdictions" relates to the net gains (losses) of those
      contracts that are not reflected in the Consolidated Statements of
      Income. These net gains (losses) are recorded as regulatory
      liabilities/assets for those subsidiaries that operate in regulated
      jurisdictions.


Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
 o The source of fair value used in determining the carrying amount of our
   total MTM asset or liability (external sources or modeled internally).
 o The maturity, by year, of our net assets/liabilities, giving an indication
   of when these MTM amounts will settle and generate cash.
<TABLE>
<CAPTION>

                                                         Maturity and Source of Fair Value of MTM
                                                           Risk Management Contract Net Assets
                                                       Fair Value of Contracts as of June 30, 2003

                                                Remainder                                                         After
                                                   2003        2004         2005        2006         2007         2007     Total
                                                   ----        ----         ----        ----         ----         ----     -----
                                                                             (in thousands)
<S>                                                <C>         <C>         <C>        <C>          <C>          <C>        <C>
Prices Provided by Other External Sources
 - OTC Broker Quotes (a)                           $3,917      $4,254     $1,429      $1,267       $  405       $  -       $11,272
Prices Based on Models and Other
 Valuation Methods (b)                                254         561        624       1,083        1,094        3,258       6,874
                                                   ------      ------     ------      ------       ------       ------     -------

    Total                                          $4,171      $4,815     $2,053      $2,350       $1,499       $3,258     $18,146
                                                   ======      ======     ======      ======       ======       ======     =======
</TABLE>

(a)     "Prices Provided by Other External Sources - OTC Broker Quotes"
         reflects  information obtained from  over-the-counter  brokers,
         industry services,  or multiple-party on-line platforms.
(b)     "Prices Based on Models and Other Valuation Methods" if there is
         absence of pricing information from external sources, modeled
         information is derived using valuation models developed by the
         reporting entity, reflecting when appropriate, option pricing theory,
         discounted cash flow concepts, valuation adjustments, etc. and may
         require projection of prices for underlying commodities beyond the
         period that prices are available from third-party sources. In addition,
         where external pricing information or market liquidity are limited,
         such valuations are classified as modeled. The determination of the
         point at which a market is no longer liquid for placing it in the
         Modeled category varies by market.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).

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.

                Total Other Comprehensive Income (Loss) Activity
                         Six Months Ended June 30, 2003

                                                        Domestic
                                                          Power
                                                          -----
                                                     (in thousands)
        Accumulated OCI, December 31, 2002               $   (48)
        ----------------------------------
        Changes in Fair Value (a)                         (1,031)
        Reclassifications from OCI to Net
         Income (b)                                           27
                                                         -------
        Accumulated OCI Derivative Gain (Loss)
         June 30, 2003                                   $(1,052)
                                                         =======

(a)      "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
(b)      "Reclassifications from OCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $715 thousand loss.

Credit Risk

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

VaR Associated with Energy Trading Contracts

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

                              June 30, 2003                                                         December 31, 2002
                              (in thousands)                                                          (in thousands)
             End        High       Average      Low                                         End        High       Average    Low
             ---        ----       -------      ---                                         ---        ----       -------    ---
<S>         <C>         <C>         <C>        <C>                                         <C>         <C>         <C>       <C>
            $146        $997        $555       $146                                        $155        $474        $170      $34

</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                            SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                                                     CONSOLIDATED STATEMENTS OF INCOME
                                                                (UNAUDITED)

                                                                  Three Months Ended June 30,             Six Months Ended June 30,
                                                                  2003                 2002               2003                2002
                                                                  ----                 ----               ----                ----
                                                                                           (in thousands)
OPERATING REVENUES:
<S>                                                             <C>                 <C>                <C>               <C>
    Electric Generation, Transmission and
     Distribution                                               $264,598            $248,849           $ 487,521         $ 448,149
    Sales to AEP Affiliates                                       16,708              14,225              49,063            37,184
                                                                --------            --------           ---------         ---------
           TOTAL OPERATING REVENUES                              281,306             263,074             536,584           485,333
                                                                --------            --------           ---------         ---------

OPERATING EXPENSES:
    Fuel for Electric Generation                                 110,706              95,207             213,716           184,090
    Purchased Electricity for Resale                              10,365               3,444              22,932             7,514
    Purchased Electricity from AEP Affiliates                    14,841              15,031              25,651            20,516
    Other Operation                                               36,656              44,131              77,513            86,282
    Maintenance                                                   18,931              20,942              31,748            32,780
    Depreciation and Amortization                                 30,868              30,533              58,903            60,673
    Taxes Other Than Income Taxes                                 13,168              12,889              29,041            27,355
    Income Taxes                                                  10,183               9,317              15,448            12,074
                                                                --------            --------           ---------         ---------
           TOTAL OPERATING EXPENSES                              245,718             231,494             474,952           431,284
                                                                --------            --------           ---------         ---------

OPERATING INCOME                                                  35,588              31,580              61,632            54,049

NONOPERATING INCOME                                                  475                 313               1,347               415

NONOPERATING EXPENSE (CREDIT)                                        355                 (20)                876               546

NONOPERATING INCOME TAX EXPENSE (CREDIT)                            (105)               (137)                (55)             (109)

INTEREST CHARGES                                                  15,223              13,895              31,077            27,713
                                                               ---------           ---------           ---------         ---------

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES             20,590              18,155              31,081            26,314

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

NET INCOME                                                        20,590              18,155              39,598            26,314

PREFERRED STOCK DIVIDEND  REQUIREMENTS                                58                  58                 115               115
                                                                --------            --------           ---------         ---------

EARNINGS APPLICABLE TO COMMON STOCK                             $ 20,532            $ 18,097           $  39,483         $  26,199
                                                                ========            ========           =========         =========

</TABLE>

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

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                                              SOUTHWESTERN ELECTRIC POWER COMPANY 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                                      $135,660       $245,003        $308,915          $   -              $689,578
Common Stock Dividends                                                               (37,927)                             (37,927)
Preferred Stock Dividends                                                               (115)                                (115)
                                                                                                                         --------
                                                                                                                          651,536
Comprehensive Income:
  Other Comprehensive Income, Net of Taxes:
   Unrealized Gain on Cash Flow Power Hedges                                                               230                230
   Net Income                                                                         26,314                               26,314
                                                                                                                         --------
     Total Comprehensive Income                                                                                            26,544
                                                     --------       --------        --------          --------           --------

JUNE 30, 2002                                        $135,660       $245,003        $297,187          $    230           $678,080
                                                     ========       ========        ========          ========           ========



JANUARY 1, 2003                                      $135,660       $245,003        $334,789          $(53,683)          $661,769
Common Stock Dividends                                                               (36,396)                             (36,396)
Preferred Stock Dividends                                                               (115)                                (115)
                                                                                                                         --------
                                                                                                                          625,258
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                      (1,004)            (1,004)
    Net Income                                                                        39,598                               39,598
                                                                                                                         --------
     Total Comprehensive Income                                                                                            38,594
                                                     --------       --------        --------          --------           --------

JUNE 30, 2003                                        $135,660       $245,003        $337,876          $(54,687)          $663,852
                                                     ========       ========        ========          ========           ========
</TABLE>

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


<PAGE>
<TABLE>
<CAPTION>
                                                  SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                                                                CONSOLIDATED BALANCE SHEETS
                                                                       (UNAUDITED)

                                                                                             June 30, 2003      December 31, 2002
                                                                                             -------------      -----------------
                                                                                                        (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                            <C>                     <C>
   Production                                                                                  $1,505,349              $1,503,722
   Transmission                                                                                   580,264                 575,003
   Distribution                                                                                 1,062,736               1,063,564
   General                                                                                        406,903                 378,130
   Construction Work in Progress                                                                   86,510                  75,755
                                                                                               ----------              ----------
        Total Electric Utility Plant                                                            3,641,762               3,596,174
   Accumulated Depreciation and Amortization                                                    1,736,945               1,697,338
                                                                                               ----------              ----------
        NET ELECTRIC UTILITY PLANT                                                              1,904,817               1,898,836
                                                                                               ----------              ----------

OTHER PROPERTY AND INVESTMENTS                                                                      6,521                   5,978
                                                                                               ----------              ----------

LONG-TERM RISK MANAGEMENT ASSETS                                                                   17,311                   5,119
                                                                                               ----------              ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                       10,500                   2,069
   Advances to Affiliates                                                                          70,945                    -
   Accounts Receivable:
      Customers                                                                                    57,192                  62,359
      Affiliated Companies                                                                         14,681                  19,253
      Allowance for Uncollectible Accounts                                                         (2,085)                 (2,128)
   Fuel Inventory                                                                                  54,665                  61,741
   Materials and Supplies                                                                          33,170                  33,539
   Under-recovered Fuel Costs                                                                        -                      2,865
   Risk Management Assets                                                                          18,688                   4,388
   Prepayments and Other                                                                           18,072                  17,851
                                                                                               ----------              ----------
          TOTAL CURRENT ASSETS                                                                    275,828                 201,937
                                                                                               ----------              ----------

REGULATORY ASSETS                                                                                  52,983                  49,233
                                                                                               ----------              ----------

DEFERRED CHARGES                                                                                   62,526                  47,572
                                                                                               ----------              ----------

          TOTAL ASSETS                                                                         $2,319,986              $2,208,675
                                                                                               ==========              ==========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>
                                               SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                                                           CONSOLIDATED BALANCE SHEETS
                                                                   (UNAUDITED)

                                                                                            June 30, 2003        December 31, 2002
                                                                                            -------------        -----------------
                                                                                                      (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                                                          <C>                      <C>
  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)                                                 (54,687)                 (53,683)
  Retained Earnings                                                                             337,876                  334,789
                                                                                             ----------               ----------
    Total Common Shareholder's Equity                                                           663,852                  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                                                                                734,418                  637,853
                                                                                             ----------               ----------
          TOTAL CAPITALIZATION                                                                1,512,970                1,414,323
                                                                                             ----------               ----------

OTHER NONCURRENT LIABILITIES                                                                     83,057                   78,494
                                                                                             ----------               ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                                             47,424                   55,595
  Advances from Affiliates, net                                                                    -                      23,239
  Accounts Payable - General                                                                     55,220                   62,139
  Accounts Payable - Affiliated Companies                                                        53,343                   58,773
  Customer Deposits                                                                              23,862                   20,110
  Taxes Accrued                                                                                  42,873                   19,081
  Interest Accrued                                                                               16,306                   17,051
  Risk Management Liabilities                                                                    12,639                    3,724
  Over-recovered Fuel                                                                               213                   17,226
  Other                                                                                          32,610                   34,565
                                                                                             ----------               ----------
          TOTAL CURRENT LIABILITIES                                                             284,490                  311,503
                                                                                             ----------               ----------

DEFERRED INCOME TAXES                                                                           348,445                  341,064
                                                                                             ----------               ----------

DEFERRED INVESTMENT TAX CREDITS                                                                  42,027                   44,190
                                                                                             ----------               ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                      42,165                   17,295
                                                                                             ----------               ----------

LONG-TERM RISK MANAGEMENT LIABILITIES                                                             6,832                    1,806
                                                                                             ----------               ----------

COMMITMENTS AND CONTINGENCIES (Note 7)

                    TOTAL CAPITALIZATION AND LIABILITIES                                     $2,319,986               $2,208,675
                                                                                             ==========               ==========

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

</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                             SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                                                    CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                 (UNAUDITED)

                                                                                                 Six Months Ended June 30,
                                                                                                2003                  2002
                                                                                                ----                  ----
                                                                                                       (in thousands)

OPERATING ACTIVITIES:
<S>                                                                                            <C>                   <C>
   Net Income                                                                                  $ 39,598              $ 26,314
   Adjustments to Reconcile Net Income to Net Cash Flows
    From Operating Activities:
      Depreciation and Amortization                                                              58,903                60,673
      Deferred Income Taxes                                                                       2,413                (9,004)
      Deferred Investment Tax Credits                                                            (2,163)               (2,262)
      Cumulative Effect of Accounting Changes                                                    (8,517)                 -
      Mark-to-Market of Risk Management Contracts                                               (13,945)                7,834
   Changes in Certain Assets and Liabilities:
      Accounts Receivable, net                                                                    9,696               (55,025)
      Fuel, Materials and Supplies                                                                7,445               (30,528)
      Accounts Payable                                                                          (12,349)               74,657
      Taxes Accrued                                                                              23,792                24,640
      Fuel Recovery                                                                             (14,148)               11,647
      Deferred Property Taxes                                                                   (18,630)              (17,545)
   Change in Other Assets                                                                         9,701                10,995
   Change in Other Liabilities                                                                   31,495               (13,802)
                                                                                               --------              --------
           Net Cash Flows From Operating Activities                                             113,291                88,594
                                                                                               --------              --------

INVESTING ACTIVITIES:
   Construction Expenditures                                                                    (62,883)              (35,695)
   Proceeds from Sale of Assets and Other                                                           414                  (284)
                                                                                               --------              --------
           Net Cash Flows Used For Investing Activities                                         (62,469)              (35,979)
                                                                                               --------              --------

FINANCING ACTIVITIES:
   Issuance of Long-term Debt                                                                   144,324               198,616
   Retirement of Long-term Debt                                                                 (56,020)             (150,450)
   Change in Advances to/from Affiliates, net                                                   (94,184)              (52,294)
   Dividends Paid on Common Stock                                                               (36,396)              (37,927)
   Dividends Paid on Cumulative Preferred Stock                                                    (115)                 (115)
                                                                                               --------              --------
           Net Cash Flows Used For Financing Activities                                         (42,391)              (42,170)
                                                                                               --------              --------

Net Increase in Cash and Cash Equivalents                                                         8,431                10,445
Cash and Cash Equivalents at Beginning of Period                                                  2,069                 5,415
                                                                                               --------              --------
Cash and Cash Equivalents at End of Period                                                     $ 10,500              $ 15,860
                                                                                               ========              ========
</TABLE>

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $27,741,000 and
$21,331,000 and for income taxes was $17,062,000 and $24,479,000 in 2003 and
2002, respectively.

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

<PAGE>
<TABLE>
<CAPTION>
                    NOTES TO RESPECTIVE FINANCIAL STATEMENTS
                                  JUNE 30, 2003
                                   (UNAUDITED)

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

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

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

3.    Cumulative Effect of        AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
        Accounting Changes

4.    Goodwill and Other          SWEPCo
        Intangible Assets

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

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

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

8.    Guarantees                  AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

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

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

11.   Leases                      OPCo

12.   Financing and Related       APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
        Activities

</TABLE>

<PAGE>
1.      GENERAL
        -------

        The accompanying unaudited interim financial statements should be read
        in conjunction with the 2002 Annual Report (as updated by the Current
        Report on Form 8-K dated May 14, 2003) 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
        on previously reported Net Income.

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

        SFAS 143 "Accounting for Asset Retirement Obligations"

        We implemented SFAS 143, "Accounting for Asset Retirement Obligations",
        effective January 1, 2003 which requires entities to record a liability
        at fair value for any legal obligations for asset retirements in the
        period incurred. Upon establishment of a legal liability, SFAS 143
        requires a corresponding asset to be established which will be
        depreciated over its useful life. SFAS 143 requires that a cumulative
        effect of change in accounting principle be recognized for the
        cumulative accretion and accumulated depreciation that would have been
        recognized had SFAS 143 been applied to existing legal obligations for
        asset retirements. In addition, the cumulative effect of change in
        accounting principle is favorably affected by the reversal of
        accumulated removal cost 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.

        We completed a review of our asset retirement obligations and concluded
        that at present, we have related legal liabilities for nuclear
        decommissioning costs for I&M's Cook Plant and TCC's partial ownership
        in the South Texas Project, as well as liabilities for the retirement of
        certain ash ponds. Since we presently recover our nuclear
        decommissioning costs in our regulated cash flow and thus had existing
        balances recorded for such nuclear retirement obligations, we 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 our
        regulated operations. In the first quarter of 2003, AEP recorded an
        unfavorable cumulative effect for our non-regulated operations. See the
        table later in this section for a summary by registrant subsidiary of
        the cumulative effect of changes in accounting principles for the six
        months ended June 30, 2003.

        Certain of AEP's registrant subsidiaries have recorded in Accumulated
        Depreciation and Amortization, removal costs collected from ratepayers
        for certain assets that do not have associated legal asset retirement
        obligations. To the extent that such registrant subsidiaries have now
        been deregulated, in the first quarter 2003 the registrant subsidiaries
        reversed the balance of such removal costs from accumulated depreciation
        which resulted in a net favorable cumulative effect in the first quarter
        of 2003. However, the registrant subsidiaries did not adjust the balance
        of such removal costs for their regulated operations, and in accordance
        with the present method of recovery, will continue to record such
        amounts through depreciation expense and accumulated depreciation.

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

                         June 30, 2003            December 31, 2002
                         -------------            -----------------
                                      (in millions)
        AEGCo                 $ 28.7                  $ 28.0
        APCo                    88.7                    94.6
        CSPCo                   98.5                    96.0
        I&M                    257.7                   250.5
        KPCo                    21.5                    23.7
        OPCo                    97.6                    97.0
        PSO                    206.2                   202.6
        SWEPCo                 223.8                   219.5
        TCC                     95.8                    97.5
        TNC                     75.4                    75.0

        The following is a summary by registrant subsidiary of the cumulative
        effect of changes in accounting principles, as a result of SFAS 143, for
        the six months ended June 30, 2003:
<TABLE>
<CAPTION>

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

                                                Reversal of                           Reversal of
                                                  Cost of                               Cost of
                            Ash Ponds             Removal          Ash Ponds            Removal
                            ---------            --------          ---------          -----------
<S>                            <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
        PSO                        -                  -                 -                  -
        SWEPCo                     -                13.0                -                 8.4
        TCC                        -                  -                 -                  -
        TNC                        -                 4.7                -                 3.1

</TABLE>

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

        The following is a reconciliation of beginning and ending aggregate
        carrying amounts of asset retirement obligations by registrant
        subsidiary following the adoption of SFAS 143:
<TABLE>
<CAPTION>
                                    Balance At                                  Balance at
                                   January 1, 2003       Accretion             June 30, 2003
                                   ---------------       ----------            -------------
<S>                                       <C>                 <C>                    <C>
        AEGCo (a)                         $  1.1              $  -                   $  1.1
        APCo (a)                            20.1                0.8                    20.9
        CSPCo (a)                            8.1                0.2                     8.3
        I&M (b)                            516.1               18.2                   534.3
        OPCo (a)                            39.5                1.6                    41.1
        TCC (c)                            203.2                7.6                   210.8
</TABLE>

              (a)   Consists of asset retirement obligations related
                    to ash ponds.
              (b)   Consists of asset retirement obligations related
                    to ash ponds ($1.1 million at June 30, 2003) and
                    nuclear decommissioning costs for the Cook Plant
                    ($533.2 million at June 30, 2003).
              (c)   Consists of asset retirement obligations related
                    to nuclear decommissioning costs for STP.


        Accretion expense is included in Other Operation expense in the
        respective Income Statements of the individual subsidiary registrants.

        As of June 30, 2003 and December 31, 2002, the fair value of assets that
        are legally restricted for purposes of settling the nuclear
        decommissioning liabilities totaled $778 million ($669 million for I&M
        and $109 million for TCC) and $716 million ($618 million for I&M and $98
        million for TCC), respectively, recorded in Nuclear Decommissioning and
        Spent Nuclear Fuel Disposal Trust Funds on I&M's Consolidated Balance
        Sheets and in Nuclear Decommissioning Trust Fund on TCC's Consolidated
        Balance Sheets.

        Pro forma net income has not been presented for the period ended June
        30, 2003 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
        not materially different from the actual amounts reported for those
        periods.

        The following is a summary by registrant subsidiary of the pro forma
        liability for asset retirement obligations which has been calculated as
        if SFAS 143 had been adopted as of the beginning of each period
        presented:

                                  December 31, 2002        December 31, 2001
                                  -----------------        -----------------
                                                (in millions)
        AEGCo                          $  1.1                  $  1.0
        APCo                             20.1                    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                                -                       -

        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. See "New Accounting Pronouncements"
        in Note 1 of the 2002 Annual Report (as updated by the Current report on
        Form 8-K dated May 14, 2003) for further information.

        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 certain decisions made by the FASB as
        part of the Derivative Implementation Group process and to incorporate
        clarifications of the definition of a derivative and which contracts
        qualify as "normal purchase/normal sale." SFAS 149 also amends certain
        other existing pronouncements. Except for certain provisions of SFAS 149
        discussed below, SFAS 149 is effective for contracts entered into or
        modified after June 30, 2003, and for hedging relationships designated
        after June 30, 2003. The provisions of SFAS 149 relating to decisions
        cleared by the FASB as part of the Derivative Implementation Group
        process shall continue to be applied in accordance with their respective
        effective dates. In addition, certain paragraphs of SFAS 149, which
        relate to forward purchases and sales of when-issued securities or other
        securities that do not yet exist, shall be applied to both existing
        contracts and new contracts entered into after June 30, 2003. We are
        currently assessing the impact of the adoption of SFAS 149.

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

        SFAS 150 was effective for us on July 1, 2003. SFAS 150 is the result of
        the first phase of the FASB's project to eliminate from the balance
        sheet the "mezzanine" presentation of items with characteristics of both
        liabilities and equity, so that no such items will be presented between
        liabilities and equity.

        SFAS 150 requires that the following three types of freestanding
        financial instruments be reported as liabilities: (1) mandatorily
        redeemable shares, (2) instruments other than shares that could require
        the issuer to buy back some of its shares in exchange for cash or other
        assets and (3) obligations that can be settled with shares, the monetary
        value of which is either (a) fixed, (b) tied to the value of a variable
        other than the issuer's shares, or (c) varies inversely with the value
        of the issuer's shares. Measurement of these liabilities generally is to
        be at fair value, with the payment or accrual of "dividends" and other
        amounts to holders reported as interest cost. Upon adoption of the new
        statement, any measurement change for these liabilities is to be
        reported as the cumulative effect of a change in accounting principle.
        We are currently assessing the impact of the adoption of SFAS 150.

        Beginning with AEP's third quarter 2003 financial statements, $321
        million ($136 million TCC, $110 million SWEPCo and $75 million PSO) of
        certain subsidiary obligated, mandatorily redeemable, preferred
        securities of subsidiary trusts holding solely junior subordinated
        debentures of such subsidiaries, $83 million ($11 million APCo, $63
        million I&M and $9 million OPCo) of mandatorily redeemable cumulative
        preferred stock of subsidiaries, and $376 million (all AEP) of equity
        unit senior notes, all of which are currently given mezzanine
        presentation, are expected to be reclassified as liabilities on the
        balance sheet. We are, however, still assessing the ultimate impact of
        SFAS 150.

        Future Accounting Changes

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

3.      CUMULATIVE EFFECT OF ACCOUNTING CHANGES
        ---------------------------------------

        SFAS 143, "Accounting for Asset Retirement Obligations" (see Note 2),
        was effective on January 1, 2003. In the first quarter of 2003, AEP's
        registrant subsidiaries recorded after-tax income related to the
        recording of Asset Retirement Obligations in their respective Statements
        of Operations as a cumulative effect of accounting change. See the
        summary by registrant subsidiary of the cumulative effect of changes in
        accounting principles recorded in the first quarter of 2003 for the
        adoptions of SFAS 143 and EITF 02-3.

        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 eliminated 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's registrant subsidiaries have recorded
        after-tax charges against net income as Accounting for Risk Management
        Contracts in their respective Statements of Operations as Cumulative
        Effect of Accounting Changes in the first quarter of 2003. This amount
        will be recognized when the positions settle.

        The following is a summary by registrant subsidiary of the cumulative
        effect of changes in accounting principles recorded in the first quarter
        of 2003 for the adoptions of SFAS 143 and EITF 02-3 (no effect on AEGCo
        or PSO):
<TABLE>
<CAPTION>

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

<S>                                    <C>                    <C>                   <C>                   <C>
       APCo                            $128.3                 $ 80.3                $ (4.7)               $ (3.0)
       CSPCo                             49.0                   29.3                  (3.1)                 (2.0)
       I&M                                 -                      -                   (4.9)                 (3.2)
       KPCo                                -                      -                   (1.7)                 (1.1)
       OPCo                             213.6                  127.3                  (4.2)                 (2.7)
       SWEPCo                            13.0                    8.4                   0.2                   0.1
       TCC                                 -                      -                    0.2                   0.1
       TNC                                4.7                    3.1                    -                     -
</TABLE>

4.      GOODWILL AND OTHER INTANGIBLE ASSETS
        ------------------------------------

        Goodwill

        There continues to be no goodwill recorded at the AEP registrant
        subsidiaries as of June 30, 2003.

        Acquired Intangible Assets

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

                                                           June 30, 2003                              December 31, 2002
                                                  -----------------------------                ------------------------------

                                                         Gross                                  Gross
                                    Amortization        Carrying       Accumulated             Carrying           Accumulated
                                       Life              Amount        Amortization             Amount           Amortization
                                    ------------        --------       ------------            --------          ------------
                                                                                  (in millions)
       <S>                              <C>                <C>             <C>                   <C>                  <C>
       Advanced royalties -
        SWEPCo                          10                 $29.4           $6.2                  $29.4                $4.7

</TABLE>

       Intangible asset amortization expense was $0.7 million for the three
       months ended June 30, 2003 and June 30, 2002 and $1.5 million for the six
       months ended June 30, 2003 and June 30, 2002. Estimated aggregate
       amortization expense is $3.0 million per year in 2004 through 2009.
       Intangible assets subject to amortization are recorded in Deferred
       Charges in SWEPCo's Consolidated Balance Sheets.

  5.   RATE MATTERS
       -----------

       Fuel in SPP - Affecting  SWEPCo and TNC

       As discussed in Note 6 of the 2002 Annual Report (as updated by the
       Current Report on Form 8-K dated May 14, 2003), in 2001, the PUCT delayed
       the start of customer choice in the SPP area of Texas. In May 2003, the
       PUCT ordered that competition would not begin in the SPP area before
       January 1, 2007. 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, for reconciling 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 thousand annually. These customers are now served by SWEPCo's REP.

       TNC Fuel Reconciliation - Affecting  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 the SPP area.
       The under-recovery balance at December 31, 2001 for TNC's service within
       SPP was $0.7 million including interest. As noted above, TNC's SPP
       customers are now being served by SWEPCo's REP.

       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.
       On May 28, 2003, the PUCT remanded TNC's final fuel reconciliation to the
       ALJ to consider several issues. Two of these remand issues could result
       in additional disallowances. The issues are the sharing of off-system
       sales margins from AEP's trading activities with customers through the
       fuel factor for five years per the PUCT's interpretation of the Texas
       AEP/CSW merger settlement and the inclusion of January 2002 fuel factor
       revenues and associated costs in the determination of the under-recovery.
       TNC made a filing on July 15, 2003 addressing the remand issues. The PUCT
       is proposing that the sharing of off-system sales margins should continue
       beyond the termination of the fuel factor. This would result in the
       sharing of margins for an additional three and one half years after the
       end of the Texas ERCOT fuel factor. Management believes that the Texas
       merger settlement only provided for sharing of margins during the period
       fuel and generation costs were regulated by the PUCT and that after a
       more thorough review of the evidence it is only reasonably possible that
       the PUCT will determine after the remand proceeding that TNC should share
       margins after the end of the Texas fuel factor. Due to a provision
       established in the first quarter, the resolution of the fuel factor issue
       should have an immaterial impact on results of operations. However, the
       decision of the PUCT could result in additional income reductions for
       these issues. It is presently expected that the ALJ's PFD and the PUCT's
       final decision of these remanded issues will occur in late 2003 or early
       2004.

       In February 2002, TNC received a final order from the PUCT in a fuel
       reconciliation covering the period July 1997 - June 2000 and reflected
       the order in its financial statements. This final order had been appealed
       to the Travis County District Court. In May 2003, the District Court
       upheld the PUCT's final order. The plaintiffs appealed the District
       Court's decision to the Third Court of Appeals.

       TCC Fuel Reconciliation  - Affecting  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 and hearings were held 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. Based upon the PUCT's
       remand of certain TNC issues, TCC established an additional reserve of $9
       million in the second quarter of 2003. An adverse ruling from the PUCT in
       excess of the reserves could have a material impact on future results of
       operations, cash flows and financial condition. Additional information
       regarding the 2004 true-up proceeding for TCC can be found in Note 6
       "Customer Choice and Industry Restructuring".

       SWEPCo Fuel Reconciliation - Affecting SWEPCo

       In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs. This
       reconciliation covers the period of January 2000 through December 2002.
       At December 31, 2002, SWEPCo's filing detailed a $2.2 million
       over-recovery balance including interest. During the reconciliation
       period, SWEPCo incurred $434.8 million of eligible fuel expense. An
       adverse ruling from the PUCT could have a material impact on future
       results of operations, cash flows and financial condition.

       ERCOT Price-to-Beat (PTB) Fuel Factor Appeal - Affecting TCC and TNC

       Several parties including the Office of Public Utility Counsel (OPC) and
       cities served by both TCC and TNC appealed the PUCT's December 2001
       orders establishing initial PTB fuel factors for Mutual Energy CPL and
       Mutual Energy WTU. On June 25, 2003, the District Court ruled in both
       appeals. The Court ruled in the Mutual Energy WTU case that the PUCT
       lacked sufficient evidence to include unaccounted for energy in the fuel
       factor, erred in including unaccounted for energy in the PTB rate based
       on its treatment in other proceedings and that the PUCT had improperly
       shifted the burden of proof from the utility to the intervening parties
       in not adjusting projected generation requirements for loss of load. The
       Court upheld the initial PTB orders on all other issues. In the Mutual
       Energy CPL proceeding, the Court ruled that the PUCT should have adjusted
       projected generation requirements for the loss of load due to retail
       competition. The Court remanded the cases to the PUCT for further
       proceedings consistent with its ruling. The amount of unaccounted for
       energy built into the PTB fuel factors was approximately $2.7 million for
       Mutual Energy WTU. At this time, management is unable to estimate the
       potential financial impact related to the loss of load issue. Management
       will appeal the District Court decisions and believes, based on the
       advice of counsel, that the PUCT's original decision will ultimately be
       upheld. If the District Court's decisions are ultimately upheld, the PUCT
       could reduce the PTB fuel factors charged to retail customers in 2002 and
       2003 resulting in an adverse effect on future results of operations and
       cash flows.

       Unbundled Cost of Service (UCOS) Appeal - Affecting  TCC

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

       McAllen Rate Review - Affecting TCC

       On June 26, 2003, the City of McAllen requested that TCC provide
       justification showing that its transmission and distribution rates should
       not be reduced. Other municipalities served by TCC have passed similar
       rate review resolutions. In Texas, municipalities have original
       jurisdiction over rates of electric utilities within their municipal
       limits. Under Texas law, TCC has a minimum of 120 days to provide support
       for its rates to the municipalities. TCC has the right to appeal any rate
       change by the municipalities to the PUCT. Pursuant to an agreement with
       the cities, TCC will file the requested support for its rates with both
       the cities and the PUCT on November 3, 2003. Management believes that a
       rate reduction is not justified.

       Louisiana Fuel Audit - Affecting SWEPCO

       As a result of complaints filed by customers, the LPSC is performing an
       audit of SWEPCo's fuel rates. Five SWEPCo customers filed a suit in the
       Caddo Parish District Court in January 2003 and filed a complaint with
       the LPSC. The customers claim that SWEPCo has overcharged them for fuel
       costs since 1975. Management believes that SWEPCo's fuel rates prior to
       1999 were proper and have been approved by the LPSC. If the LPSC or the
       Court rules against SWEPCo, it could have an adverse impact on results of
       operations and cash flows.

       FERC Wholesale Fuel Complaints - Affecting TNC

       As discussed in the 2002 Annual Report (as updated by the Current Report
       on Form 8-K dated May 14, 2003), 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 was filed
       at FERC in June 2003 regarding the fuel complaint and new contracts.
       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. TNC anticipates that the provision
       for refund will be adequate to cover the financial implications resulting
       from these new contracts. Should FERC fail to approve the settlement and
       new contracts, the actual refund and final resolution of this matter
       could differ materially from the provision and may have a negative impact
       on future results of operations, cash flows and financial condition.

       Environmental Surcharge Filing - Affecting KPCo

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

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

       PSO Rate Review - Affecting PSO

       In February 2003, the Director of the Oklahoma Corporation Commission
       (OCC) filed an application requiring PSO to file all documents necessary
       for a general rate review before August 1, 2003. The required date to
       file the case was subsequently changed to October 31, 2003. Management is
       unable to predict the ultimate effect of this review on PSO's rates.

       PSO Fuel and Purchased Power - Affecting PSO

       As discussed in Note 6 of the 2002 Annual Report (as updated by the
       Current Report on Form 8-K dated May 14, 2003), PSO had a $44 million
       under-recovery of fuel costs resulting from a reallocation of purchased
       power costs for periods prior to January 1, 2002. On July 23, 2003, PSO
       filed with the OCC seeking recovery of the $44 million over an eighteen
       month time period. A hearing has been scheduled for October 7, 2003. If
       the OCC does not permit recovery, there will be an adverse effect on
       results of operations, cash flows and possibly financial condition.

       Virginia Fuel Factor Filing - Affecting APCo

       APCo filed with the Virginia SCC to reduce its fuel factor effective
       August 1, 2003. The requested fuel rate reduction would be effective for
       17 months and is estimated to reduce revenues by $36 million. By order
       dated July 23, 2003, the Virginia SCC approved APCo's requested fuel
       factor reduction on an interim basis, subject to further investigation.
       This fuel factor adjustment will reduce cash flows without impacting
       results of operations as any over-recovery of fuel costs would be
       deferred as a regulatory liability.

       FERC Long-term Contracts - Affecting 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.

       RTO Formation/Integration Costs - Affecting APCo, CSPCo, I&M, KPCo, and
         OPCo

       With FERC approval, AEP East companies have been deferring costs incurred
       under FERC orders to form an RTO (the Alliance RTO) or join an existing
       RTO (PJM). On July 2, 2003, the FERC issued an order approving our
       continued deferral of both our Alliance formation costs and our PJM
       integration costs including the deferral of a carrying charge. The AEP
       East companies have deferred approximately $22 million of RTO formation
       and integration costs and related carrying charges (APCo-$6 million,
       CSPCo-$3 million, I&M-$5 million, KPCo-$1 million, OPCo-$7 million)
       through June 30, 2003. As a result of the subsequent delay in the
       integration of AEP's East transmission system into PJM, FERC declined to
       rule, at this time, on our request to transfer the deferrals to
       regulatory assets, and to maintain the deferrals until such time as the
       costs can be recovered from all users of AEP's East transmission system.
       The AEP East companies will apply for permission to transfer the deferred
       formation/integration costs to a regulatory asset prior to integration
       with PJM.

       In the first quarter of 2003, the state of Virginia enacted legislation
       preventing APCo from joining an RTO until after June 30, 2004 and only
       then with the approval of the Virginia SCC. In the second quarter of
       2003, the KPSC denied KPCo's request that they approve our joining PJM
       based in part on a lack of evidence that it would benefit Kentucky retail
       customers. Management intends to seek a rehearing in Kentucky. Management
       does not expect the integration with PJM to occur prior to June 30, 2004.
       In its July 2 order, FERC indicated that it would review the deferred
       costs for prudency at the time they are transferred to a regulatory asset
       account and scheduled for amortization and recovery in the open access
       transmission tariff (OATT) to be charged by PJM. Management believes that
       the FERC will grant permission for the deferred RTO costs to be amortized
       and included in the OATT.

       Whether the amortized costs will be fully recoverable depends upon the
       state regulatory commissions' treatment of AEP's East companies' portion
       of the OATT at the time they join PJM. Presently, retail rates are frozen
       or capped and cannot be increased for retail customers of CSPCo, I&M and
       OPCo. AEP intends to apply with FERC seeking permission to delay the
       amortization of the deferred RTO formation/integration costs until they
       are recoverable from all users of the transmission system including
       retail customers. Management is unable to predict the timing of when AEP
       will join PJM and if upon joining PJM whether FERC will grant a delay of
       recovery until the rate caps and freezes end. Management intends to seek
       recovery of the deferred RTO formation/integration costs. If the FERC
       ultimately decides not to approve a delay or the state commissions deny
       recovery, future results of operations and cash flows could be adversely
       affected.

       FERC Order on Regional Through and Out Rates (RTOR) - Affecting APCo,
         CSPCo, I&M, KPCo and OPCo

       On July 23, 2003, the FERC issued an order directing PJM and the Midwest
       ISO to make compliance filings for their respective Open Access
       Transmission Tariffs to eliminate, by November 1, 2003, the Regional
       Through and Out Rates (RTOR) on transactions where the energy is
       delivered within the Midwest ISO and PJM regions. The elimination of the
       RTORs will reduce the transmission service revenues collected by the RTOs
       and thereby reduce the revenues received by transmission owners under the
       RTOs' revenue distribution protocols. The order provided that affected
       Transmission Owners could file to offset the elimination of these
       revenues by increasing rates or utilizing a transitional rate mechanism
       to recover lost revenues that result from the elimination of the RTORs.
       The FERC also found that the through and out rates of some of the former
       Alliance RTO Companies, including AEP, may be unjust, unreasonable, and
       unduly discriminatory or preferential for energy delivered in the Midwest
       ISO/PJM regions. FERC has initiated an investigation and hearing in
       regard to these rates. AEP will make a filing with the FERC supporting
       the justness and reasonableness of its rates by August 15, 2003.
       Management at this time is unable to predict the ultimate outcome of this
       investigation, or the impact on the results of operations and cash flows.

  6.   CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
       ------------------------------------------

       As discussed in the 2002 Annual Report (as updated by the Current Report
       on Form 8-K dated May 14, 2003), retail customer choice began in four of
       the eleven state retail jurisdictions (Michigan, Ohio, Texas and
       Virginia) in which the AEP domestic electric utility companies operate.
       The following paragraphs discuss significant events occurring in 2003
       related to customer choice and industry restructuring.

       Ohio Restructuring - Affecting CSPCo and OPCo

       On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy
       Users-Ohio and American Municipal Power-Ohio filed a complaint with the
       PUCO alleging that CSPCo and OPCo have violated the PUCO's orders
       regarding implementation of their transition plan and violated other
       applicable law by failing to participate in an RTO.

        The complainants seek, among other relief, an order from the PUCO:
             o  suspending collection of transition charges by CSPCo and
                OPCo until transfer of control of their transmission assets
                has occurred
             o  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. CSPCo and OPCo filed
        comments and responses in compliance with the PUCO's schedule.
        Management is unable to predict the timing or the outcome of this
        proceeding.

        The Ohio Act provides for a Development Period during which retail
        customers can choose their electric power suppliers or have the
        protection of Default Service at frozen generation rates from the
        incumbent utility. The Development Period began on January 1, 2001 and
        will terminate no later than December 31, 2005, but the PUCO may
        terminate the Development Period for one or more customer classes before
        that date if it determines either that effective competition exists in
        the incumbent utility's certified territory or that there is a twenty
        percent switching rate of the incumbent utility's load by customer
        class. Following the Development Period, retail customers will receive
        distribution and transmission service from the incumbent utility whose
        distribution rates will be approved by the PUCO and whose transmission
        rates will be approved by the FERC. Retail customers will continue to
        have the right to choose their electric power suppliers or have the
        protection of Default Service which must be offered by the incumbent
        utility at market rates. The PUCO has circulated a draft of proposed
        rules but has not yet identified the method by which it will determine
        market rates for Default Service following the Development Period.

        As provided in the stipulation agreement approved by the PUCO, CSPCo and
        OPCo are deferring customer choice implementation costs in excess of $20
        million per company. The agreements provide for the deferral of these
        costs as a regulatory asset until the company's next distribution base
        rate case. CSPCo has deferred $10 million and OPCo has deferred $12
        million of such costs. Recovery of these regulatory assets will be
        subject to PUCO review in each company's next Ohio distribution rate
        filings which will not occur until after 2008 for CSPCo and 2007 for
        OPCo. Management believes that the amounts deferred represent prudently
        incurred customer choice implementation costs and should be recoverable
        in future rates. If the PUCO determines that any of the deferred costs
        are unrecoverable, it would have an adverse impact on future results of
        operations and cash flows.

        Texas Restructuring - Affecting SWEPCo, TCC and TNC

        As discussed in the 2002 Annual Report (as updated by the Current Report
        on Form 8-K dated May 14, 2003), 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), a true-up of the power costs used in the PUCT's ECOM model
        for 2002 and 2003 to reflect actual market prices determined through
        legislatively-mandated capacity auctions (Wholesale capacity auction
        true-up) 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 review in the 2004 true-up
        proceedings. The PUCT adopted a rule 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 wholesale capacity auction true-up adjustment for
        TCC for the 2004 true-up proceeding.

        The decision to determine stranded costs by selling TCC's generating
        plants and the expectation that the sales price would produce a
        significant loss/stranded costs instead of using the PUCT's ECOM model
        estimates, enabled TCC to record in 2002 a $262 million regulatory asset
        and related revenues which represents the quantifiable amount of the
        wholesale capacity auction true-up for the year 2002. Through June 30,
        2003, TCC recorded an additional $108 million regulatory asset and
        related revenues for the wholesale capacity auction true-up. 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 they can not be recovered unless there are stranded costs.
        As discussed above, a defined process is required in order to determine
        the amount of stranded costs related to generation facilities for the
        2004 true-up proceedings.

        In June 2003, the PUCT Staff proposed a refinement in the calculation of
        the wholesale capacity auction true-up. The Staff's proposed methodology
        could result in a material change in the amount of the wholesale
        capacity auction true-up for 2002 and 2003. The PUCT Staff's proposed
        true-up filing package has been published for comments that are due in
        September. A final true-up filing package is expected to be adopted by
        the end of 2003.

        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 competition 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, other true-up
        adjustments 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 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 six months 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 APCo

        APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the
        first quarter of 2003 after new developments during the quarter prompted
        an analysis of the probability of restructuring becoming effective.

        In 2000, the WVPSC issued an order approving an electricity
        restructuring plan, which the WV Legislature approved by joint
        resolution. The joint resolution provided that the WVPSC could not
        implement the plan until the WV legislature made tax law changes
        necessary to preserve the revenues of state and local governments.

        In the 2001 and 2002 legislative sessions, the WV Legislature failed to
        enact the required legislation that would allow the WVPSC to implement
        the restructuring plan. Due to this lack of legislative activity, the
        WVPSC closed two proceedings related to electricity restructuring during
        the summer of 2002.

        In the 2003 legislative session, the WV Legislature failed to enact the
        required tax legislation. Also, 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
        restructuring 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 reapply SFAS 71.

        The result of reapplying SFAS 71 in WV had an insignificant effect on
        results of operations during the first six months 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
        marked-to-market.

7.      COMMITMENTS AND CONTINGENCIES
        -----------------------------

        Nuclear Plant Outages - Affecting I&M and TCC

        In April 2003, engineers at STP, during inspections conducted regularly
        as part of refueling outages, found wall cracks in two bottom mounted
        instrument guide tubes of STP Unit 1. These cracks have been repaired
        and the unit is expected to return to service in late summer. TCC's
        share of the direct cost of repair was approximately $6 million through
        June 30, 2003. STP officials are working closely with the NRC to safely
        return the unit to service. We have commitments to provide power to
        customers during the outage. Therefore, we will be subject to
        fluctuations in the market prices of electricity and purchased
        replacement energy could be a significant cost.

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

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

        As discussed in Note 9 of the Combined Notes to Financial Statements in
        the 2002 Annual Report (as updated by the Current Report on Form 8-K
        dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
        Proceedings", 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 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 our 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 requirements began in May 2003
        for TCC and begin in May 2005 for SWEPCo.

        We are 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. In May 2003,
        SCR technology installed at Big Sandy and Cardinal plants commenced
        operation. 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 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 $976 million has been spent through
        June 30, 2003. Estimated compliance cost ranges and amounts spent by
        registrant subsidiaries are as follows:

                            Estimated               Amount
                         Compliance Costs            Spent
                         ----------------            -----
                                      (in millions)
               AEGCo         $   28                  $  6
               APCo             462                   261
               CSPCo             87                    61
               I&M               39                     9
               KPCo             180                   177
               OPCo         524-853                   427
               SWEPCo            35                    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.

        Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC

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

        FERC Proposed Standard Market Design - Affecting AEP System

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

        FERC Proposed Security Standards - Affecting AEP System

        As part of the SMD proposed rulemaking, in July 2002, FERC published for
        comment proposed security standards. These standards were intended to
        ensure that all market participants would have a basic security program
        that would effectively protect the electric grid and related market
        activities. As proposed, these standards would apply to AEP's power
        transmission systems, distribution systems and related areas of
        business. The proposed standards have not been adopted. Subsequently, in
        2002, the North American Electric Reliability Council (NERC), with
        FERC's support, developed a new set of standards to address industry
        compliance. These new standards closely parallel the initial, proposed
        FERC standards in both content and compliance time frames, and were
        approved by the NERC ballot body in June of 2003. AEP is developing
        financial requirements for security implementation and compliance with
        these NERC standards. Since these financial requirements are not yet
        determined, management cannot predict the impacts of such standards on
        future results of operations and cash flows.

  8.    GUARANTEES
        ----------

        In November 2002, the FASB issued FIN 45 which clarifies the accounting
        to recognize a liability related to issuing a guarantee, as well as
        additional disclosures of guarantees. 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 were
        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 any guarantees entered into by
        AEP's registrant subsidiaries 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 by an AEP subsidiary in
        the subsidiaries' ordinary course of business. TCC issued an LOC for
        credit enhancement of issued bonds. At June 30, 2003, the maximum future
        payments of all the LOCs are approximately $163 million with maturities
        ranging from July 2003 to January 2011. TCC's LOC was for approximately
        $40.9 million with a maturity date of November 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-
        party obligations:

        In connection with reducing the cost of the lignite mining contract for
        its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain
        conditions, to assume the obligations under a revolving credit
        agreement, capital lease obligations, and term loan payments of the
        mining contractor, Sabine Mining Company (Sabine). In the event Sabine
        defaults under any of these agreements, SWEPCo's total future maximum
        payment exposure is approximately $61 million with maturity dates
        ranging from June 2005 to February 2012.

        As part of the process to receive a renewal of a Texas Railroad
        Commission permit for lignite mining, SWEPCo has agreed to provide
        guarantees of mine reclamation in the amount of approximately $85
        million. Since SWEPCo uses self-bonding, the guarantee provides for
        SWEPCo to commit to use its resources to complete the reclamation in the
        event the work is not completed by a third party miner. At June 30,
        2003, the cost to reclaim the mine in 2035 is estimated to be
        approximately $36 million. This guarantee ends upon depletion of
        reserves estimated at 2035 plus 6 years to complete reclamation.

        It is reasonably possible that due to the guarantees and contracts in
        place with Sabine that SWEPCo will consolidate Sabine in the third
        quarter of 2003, as a result of the issuance of FIN 46. Upon
        consolidation, SWEPCo would record the assets, liabilities, depreciation
        expense, minority interest and debt interest expense of Sabine. SWEPCo
        would eliminate expenses associated with the mining contract against
        Sabine's revenues.

        See Note 11 "Leases" for disclosure of lease residual value guarantees.

        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 registrant subsidiaries' exposure generally does not exceed the
        sale price. AEP's registrant subsidiaries 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
        six months of 2003, AEP's registrant subsidiaries entered into sale
        agreements which included indemnifications with a maximum exposure that
        was not significant for any individual registrant subsidiary. There are
        no material liabilities recorded for any indemnifications entered during
        the first six months of 2003. There are no liabilities recorded for any
        indemnifications 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 June 30, 2003, AEP's maximum potential loss for
        these lease agreements was approximately $27 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                              $ 1
                        CSPCo                               1
                        I&M                                 2
                        KPCo                                1
                        OPCo                                3
                        PSO                                 3
                        SWEPCo                              3
                        TCC                                 6
                        TNC                                 2
                        Other AEP Subsidiaries              5
                                                          ---

                        Total  AEP                        $27
                                                          ===

9.      SUSTAINED EARNINGS IMPROVEMENT INITIATIVE
        -----------------------------------------

        In response to difficult conditions in our business, a Sustained
        Earnings Improvement (SEI) initiative was undertaken company-wide in the
        fourth quarter of 2002, as a cost-saving and revenue-building effort to
        build long-term earnings growth. Termination benefits expense relating
        to terminated employees was recorded in the fourth quarter of 2002. The
        termination benefits expense was classified as Other Operation expense
        on the statements of operations. No additional termination benefits
        expense related to the SEI initiative was recorded during the first and
        second quarters of 2003, and significantly all SEI related payments have
        been made as of June 30, 2003.

        See Note 11 "Sustained Earnings Improvement Initiative" in our 2002
        Annual Report (as updated by the Current Report on Form 8-K dated May
        14, 2003) for further information on expenses recorded by registrant
        subsidiary during the fourth quarter 2002 related to the SEI initiative.

10.     BUSINESS SEGMENTS
        -----------------

        All of AEP's registrant subsidiaries have one reportable segment. The
        one reportable segment is a vertically integrated electricity
        generation, transmission and distribution business except AEGCo, an
        electricity generation business. All of the registrants' other
        activities are insignificant. The registrant subsidiaries operations are
        managed on an integrated basis because of the substantial impact of
        bundled cost-based rates and regulatory oversight on the business
        process, cost structures and operating results.

11.     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 June 30, 2003, AEP has determined that OPCo will consolidate JMG in
        the third quarter of 2003 as a result of the issuance of FIN 46. Upon
        consolidation, OPCo will record the assets, liabilities, depreciation
        expense, minority interest and debt interest expense of JMG. OPCo will
        eliminate operating lease expense against JMG's rental revenues. As of
        June 30, 2003, the Company is still reviewing the impact of the
        consolidation, but will have to record the cumulative effect (net of
        tax) due to a change in accounting principle. 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 June 30, 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." The asset will be amortized over the
        remaining lease term, which ends in the first quarter of 2010.

12.     FINANCING AND RELATED ACTIVITIES
        --------------------------------

        Long-term debt and other securities issuances and retirements during the
        first six months of 2003 were:
<TABLE>
<CAPTION>

                                Type                    Principal         Interest        Due
           Company            of Debt                    Amount              Rate         Date
           -------            -------                 -----------         --------        ----
           Issuances                                 (in millions)          (%)
           ---------

             <S>                <C>                        <C>              <C>           <C>
             APCo               Senior Unsecured Notes     $200             3.60          2008
             APCo               Senior Unsecured Notes      200             5.95          2033
             APCo               Installment Purchase
                                  Contracts                 100             5.50          2022
             CSPCo              Senior Unsecured Notes      250             5.50          2013
             CSPCo              Senior Unsecured Notes      250             6.60          2033
             KPCo               Senior Unsecured Notes       75             5.625         2032
             OPCo               Senior Unsecured Notes      250             5.50          2013
             OPCo               Senior Unsecured Notes      250             6.60          2033
             SWEPCo             Senior Unsecured Notes      100             5.375         2015
             SWEPCo             Secured Note                 44             4.47          2011
             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
</TABLE>
<TABLE>
<CAPTION>

                               Type                          Principal          Interest           Due
         Company              of Debt                         Amount              Rate             Date
         -------              -------                       -----------         --------           ----
         Retirements                                       (in millions)          (%)
         -----------
             <S>                <C>                             <C>                <C>             <C>
             APCo               First Mortgage Bonds           $ 70                8.50            2022
             APCo               First Mortgage Bonds             30                7.80            2023
             APCo               First Mortgage Bonds             20                7.15            2023
             APCo               Installment Purchase
                                  Contracts                      10                7.875           2013
             APCo               Installment Purchase
                                  Contracts                      40                6.85            2022
             APCo               Installment Purchase
                                  Contracts                      50                6.60            2022
             APCo               Senior Unsecured Notes          100                7.20            2038
             APCo               Senior Unsecured Notes          100                7.30            2038
             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
             CSPCo              First Mortgage Bonds             13                6.80            2003
             CSPCo              First Mortgage Bonds             26                6.55            2004
             CSPCo              First Mortgage Bonds             26                6.75            2004
             CSPCo              First Mortgage Bonds             40                7.90            2023
             CSPCo              First Mortgage Bonds             33                7.75            2023
             I&M                First Mortgage Bonds             75                8.50            2022
             I&M                First Mortgage Bonds             15                7.35            2023
             I&M                Junior Debentures                40                8.00            2026
             I&M                Junior Debentures               125                7.60            2038
             KPCo               Junior Debentures                40                8.72            2025
             OPCo               First Mortgage Bonds             30                6.75            2003
             PSO                First Mortgage Bonds             35                6.25            2003
             SWEPCo             First Mortgage Bonds             55                6.625           2003
             SWEPCo             Secured Note                      1                4.47            2011
             TCC                First Mortgage Bonds             18                7.50            2023
             TCC                First Mortgage Bonds             16                6.875           2003
             TCC                Securitization Bonds             32                3.54            2005

</TABLE>
<TABLE>
<CAPTION>

        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)              (%)
         -----------
          <S>               <C>                         <C>                   <C>              <C>
          CSPCo             Notes Payable               $160                  6.501            2006
          KPCo              Notes Payable                 15                  4.336            2003
          OPCo              Notes Payable                240                  6.501            2006
          OPCo              Notes Payable                 60                  4.336            2003
</TABLE>

        In July 2003, OPCo issued the following Senior Unsecured Notes:

             Principal                                               Due
              Amount                     Interest Rate               Date
            -----------                  -------------               ----
            (in millions)                     (%)

           $225 million                      4.85%                    2014
            225 million                      6.375%                   2033

<PAGE>

                             CONTROLS AND PROCEDURES


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

As of June 30, 2003, these officers concluded that the disclosure controls and
procedures in place provide reasonable assurance that the disclosure controls
and procedures can accomplish their objectives. AEP continually strives to
improve its disclosure controls and procedures to enhance the quality of its
financial reporting and to maintain dynamic systems that change as conditions
warrant.

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

<PAGE>

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.
         -----------------

For a discussion of material legal proceedings, see Note 8 to AEP's consolidated
financial statements and Note 7 to AEP's registrant subsidiaries' respective
financial statements, both entitled Commitments and Contingencies, incorporated
herein by reference.

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 (as updated by the Current Report on Form 8-K dated May 14, 2003),
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 that claims for civil penalties are limited to the
five-year period prior to the filing date of the complaints. There is no time
limit on claims for injunctive relief.

On August 7, 2003 the District Court issued a decision following a liability
trial in a similar case pending in the Southern District of Ohio against Ohio
Edison Company, an unrelated utility. The District Court held that replacements
of major boiler and turbine components that are infrequently performed at a
single unit, that are performed with the assistance of outside contractors, that
are accounted for as capital expenditures, and that require the unit to be taken
out of service for a number of months are not "routine" maintenance, repair, and
replacement. The District Court also held that a comparison of past actual
emissions to projected future emissions must be performed prior to any
non-routine physical change in order to evaluate whether an emissions increase
will occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all of the
challenged activities in that case were not routine, and that the changes
resulted in significant net increases in emissions for certain pollutants. A
remedy trial is scheduled for March 2004.

Management believes that the Ohio Edison decision fails to properly evaluate and
apply the applicable legal standards. The facts in the AEP case also vary widely
from plant to plant. Further, the Ohio Edison decision is limited to liability
issues, and provides no insight as to the remedies that might ultimately be
ordered by the Court.

On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued
an order invalidating the administrative compliance order issued by Federal EPA
to the Tennessee Valley Authority for similar alleged violations. The 11th
Circuit determined that the administrative compliance order was not a final
agency action, and that the enforcement provisions authorizing the issuance and
enforcement of such orders under the Clean Air Act is unconstitutional.

On June 26, 2003, the United States Circuit Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG),
of which the AEP subsidiaries are members, to reopen petitions for review of the
1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA
claims in the AEP case and other related cases. On August 4, 2003, UARG filed a
motion to separate and expedite review of their challenges to the 1980 and 1992
rulemakings from other unrelated claims in the consolidated appeal. The central
issue in these petitions concerns the lawfulness of the emissions increase test,
as currently interpreted and applied by Federal EPA in its utility enforcement
actions. A decision by the D. C. Circuit could significantly impact further
proceedings in the AEP case.

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.

Item 4.  Submission of Matters to a Vote of Security Holders.
         ---------------------------------------------------

AEP

        The annual meeting of shareholders was held in Columbus, Ohio, on April
23, 2003. The holders of shares entitled to vote at the meeting or their proxies
cast votes at the meeting with respect to the following three matters, as
indicated below:

        1.     Election of thirteen directors to hold office until the next
               annual meeting and until their successors are duly elected. Each
               nominee for director received the votes of shareholders as
               follows:
<TABLE>
<CAPTION>

                                                          Number of Shares                  Number of
                       Nominee                                Voted For                  Votes Withheld
                       -------                            ----------------               --------------
               <S>                                           <C>                           <C>
               E. R. Brooks                                  309,487,577                   12,115,867
               Donald M. Carlton                             308,370,730                   13,232,714
               John P. DesBarres                             309,518,825                   12,084,619
               E. Linn Draper, Jr.                           312,545,954                     9,057,490
               Robert W. Fri                                 309,219,713                   12,383,731
               William R. Howell                             309,136,662                   12,466,782
               Lester A. Hudson, Jr.                         312,679,273                    8,924,171
               Leonard J. Kujawa                             308,147,027                   13,456,417
               Richard L. Sandor                             309,363,867                   12,239,577
               Thomas V. Shockley, III                       312,652,348                    8,951,096
               Donald G. Smith                               309,277,366                   12,326,078
               Linda Gillespie Stuntz                        309,251,337                   12,352,107
               Kathryn D. Sullivan                           308,205,408                   13,398,036
</TABLE>

        2. Shareholder proposal submitted by First Investors Trust. The proposal
           was disapproved by a vote of the shareholders as follows:

               Votes FOR                                          39,599,579
               Votes AGAINST                                     203,803,580
               Votes ABSTAINED                                     6,390,989
               Broker NON-VOTES*                                  71,809,331

        3.     Shareholder proposal submitted by Connecticut Retirement and
               Trust Funds and Christian Brothers Investment Services, Inc. The
               proposal was disapproved by a vote of the shareholders as
               follows:

               Votes FOR                                       58,589,132
               Votes AGAINST                                  159,143,612
               Votes ABSTAINED                                 32,068,627
               Broker NON-VOTES*                               71,802,108

               *A non-vote occurs when a nominee holding shares for a beneficial
                owner votes on one proposal, but does not vote on another
                proposal because the nominee does not have discretionary
                voting power and has not received instructions from the
                beneficial owner.


APCo

        The annual meeting of stockholders was held on April 22, 2003 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR
each of the following seven persons for election as directors and there were no
votes withheld and such persons were elected directors to hold office for one
year or until their successors are elected and qualify:
               E. Linn Draper, Jr.           Robert P. Powers
               Henry W. Fayne                Thomas V. Shockley, III
               Thomas M. Hagan               Susan Tomasky
               Armando A. Pena

TCC

        Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 10, 2003, the following seven persons were
elected directors to hold office for one year or until their successors are
elected and qualify:

               E. Linn Draper, Jr.           Robert P. Powers
               Henry W. Fayne                Thomas V. Shockley, III
               Thomas M. Hagan               Susan Tomasky
               Armando A. Pena

I&M

        Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 22, 2003, the following thirteen persons were
elected directors to hold office for one year or until their successors are
elected and qualify:

               Karl G. Boyd                  Susanne M. Moorman
               E. Linn Draper, Jr.           Robert P. Powers
               John E. Ehler                 John R. Sampson
               Henry W. Fayne                Thomas V. Shockley, III
               Thomas M. Hagan               David B. Synowiec
               David L. Lahrman              Susan Tomasky
               Marc E. Lewis

OPCo

        The annual meeting of shareholders was held on May 6, 2003 at 1
Riverside Plaza, Columbus, Ohio. At the meeting there were 27,952,473 votes cast
FOR:

        Each of the following seven persons for election as directors and there
        were no votes withheld and such persons were elected directors to hold
        office for one year or until their successors are elected and qualify:

               E. Linn Draper, Jr.           Robert P. Powers
               Henry W. Fayne                Thomas V. Shockley, III
               Thomas M. Hagan               Susan Tomasky
               Armando A. Pena

SWEPCo

        Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 9, 2003, the following seven persons were
elected directors to hold office for one year or until their successors are
elected and qualify:

               E. Linn Draper, Jr.           Robert P. Powers
               Henry W. Fayne                Thomas V. Shockley, III
               Thomas M. Hagan               Susan Tomasky
               Armando A. Pena


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 31.1 - Certification of Chief Executive Officer Pursuant
               to Section 302 of the Sarbanes-Oxley Act of 2002.

               Exhibit 31.2 - Certification of Chief Financial Officer Pursuant
               to Section 302 of the Sarbanes-Oxley Act of 2002.

               Exhibit 32.1 - Certification of Chief Executive Officer Pursuant
               to Section 1350 of Chapter 63 of Title 18 of the United States
               Code.

               Exhibit 32.2 - 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
        June 30, 2003.
<TABLE>
<CAPTION>

        Company Reporting              Date of Report              Item Reported
        -----------------              --------------              -------------
        <S>                             <C>                        <C>
        AEP, APCo, CSPCo,               May 14, 2003               Item 5. Other Events and
           I&M, KPCo, OPCo,                                         Regulation FD Disclosure
           PSO, SWEPCo, TCC, TNC                                   Item 7. Financial Statements
                                                                    and Exhibits
        APCo                            April 30, 2003             Item 5. Other Events and
                                                                    Regulation FD Disclosure
                                                                   Item 7. Financial Statements
                                                                    And Exhibits
        KPCo                            June 13, 2003              Item 5. Other Events and
                                                                    Regulation FD Disclosure
                                                                   Item 7. Financial Statements
                                                                    And Exhibits
        SWEPCo                          April 8, 2003              Item 5. Other Events and
                                                                    Regulation FD Disclosure
                                                                   Item 7. Financial Statements
                                                                    And Exhibits
</TABLE>

<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: August 12, 2003