<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 SEPTEMBER 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.
-----------                 ----------------------------------                                                ------------------

<C>                         <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 October 31, 2003 was 395,007,320.

<PAGE>
<TABLE>
<CAPTION>
                               AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                           INDEX TO QUARTERLY REPORT ON FORM 10-Q
                                                     September 30, 2003

                                                                                                                    Page
                                                                                                                    ----
   <C>                                                                                                              <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-19
                              Consolidated Financial Statements                                                     A-20 - A-25
                              Notes to Consolidated Financial Statements                                            A-26 - A-57

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

                         AEP Texas Central Company and Subsidiary:
                              Management's Financial Discussion and Analysis                                        C-1 - C-8
                              Consolidated Financial Statements                                                     C-9 - C-12

                         AEP Texas North Company:
                              Management's Narrative Financial Discussion and Analysis                              D-1 - D-6
                              Financial Statements                                                                  D-7 - D-11

                         Appalachian Power Company and Subsidiaries:
                              Management's Financial Discussion and Analysis                                        E-1 - E-7
                              Consolidated Financial Statements                                                     E-8 - E-12

                         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-6
                              Consolidated Financial Statements                                                     G-7 - G-11

                         Kentucky Power Company:
                              Management's Narrative Financial Discussion and Analysis                              H-1 - H-6
                              Financial Statements                                                                  H-7 - H-11

                         Ohio Power Company Consolidated:
                              Management's Financial Discussion and Analysis                                        I-1 - I-7
                              Consolidated Financial Statements                                                     I-8 - I-12

                         Public Service Company of Oklahoma:
                              Management's Narrative Financial Discussion and Analysis                              J-1 - J-5
                              Financial Statements                                                                  J-6 - J-10

                         Southwestern Electric Power Company Consolidated:
                              Management's Financial Discussion and Analysis                                        K-1 - K-6
                              Consolidated Financial Statements                                                     K-7 - K-11

                         Notes to Respective Financial Statements                                                   L-1 - L-24

       Item 4.            Controls and Procedures                                                                   M-1

   Part II.           OTHER INFORMATION
       Item 1.            Legal Proceedings                                                                         N-1
       Item 5.            Other Information                                                                         N-1
       Item 6.            Exhibits and Reports on Form 8-K                                                          N-1
                                     (a)     Exhibits: Exhibit 12 Exhibit 31.1
                                             Exhibit 31.2 Exhibit 32.1 Exhibit
                                             32.2
                                     (b)     Reports on Form 8-K

   SIGNATURE                                                                                                        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 and consolidated affiliates.
AEP Credit                         AEP Credit,  Inc., a subsidiary of AEP which factors  accounts  receivable and accrued utility
                                            revenues for affiliated domestic electric utility companies.
AEP East companies                 APCo, CSPCo, I&M, KPCo and OPCo.
AEPES                              AEP Energy Services, Inc., a subsidiary of AEPR.
AEPR                               AEP Resources, Inc.
AEP System or the System           The American Electric Power System, an integrated electric utility system, owned and
                                            operated by AEP's electric utility subsidiaries.
AEPSC                              American Electric Power Service Corporation, a service subsidiary providing management and
                                            professional services to AEP and its subsidiaries.
AEP 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.
AFUDC                              Allowance for funds used during construction, a noncash nonoperating income item that is
                                            capitalized and recovered through depreciation over the service life of domestic
                                            regulated electric utility plant.
Amos Plant                         John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APB 18                             Accounting   Principles  Board  Opinion  Number  18:  The  Equity  Method  of  Accounting  for
                                            Investments in Common Stock.
APCo                               Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission                Arkansas Public Service Commission.
Buckeye                            Buckeye Power, Inc., an unaffiliated corporation.
COLI                               Corporate owned life insurance program.
Cook Plant                         The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo                              Columbus Southern Power Company, an AEP electric utility subsidiary.
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, an AEP subsidiary.
LPSC                               Louisiana Public Service Commission.
Michigan Legislation               The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
                                            customer choice of electricity supplier.
MISO                               Midwest Independent System Operator (an independent operator of transmission assets in the
                                            Midwest).
MLR                                Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool                         AEP System's Money Pool.
MPSC                               Michigan Public Service Commission.
MTM                                Mark-to-Market.
MW                                 Megawatt.
MWH                                Megawatthour.
NOx                                Nitrogen oxide.
NOx Rule                           A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states
                                            including seven of the states in which AEP companies operate.
NRC                                Nuclear Regulatory Commission.
OCC                                The Corporation Commission of the State of Oklahoma.
Ohio Act                           The Ohio Electric Restructuring Act of 1999.
Ohio EPA                           Ohio Environmental Protection Agency.
OPCo                               Ohio Power Company, an AEP electric utility subsidiary.
PJM                                Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO                                Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTB                                Price-to-Beat.
PUCO                               The Public Utilities Commission of Ohio.
PUCT                               The Public Utility Commission of Texas.
PUHCA                              Public Utility Holding Company Act of 1935, as amended.
PURPA                              The Public Utility Regulatory Policies Act of 1978.
RCRA                               Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries            AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
                                            TCC and TNC.
REP                                Retail Electric Provider.
Rockport Plant                     A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
                                            Indiana owned by AEGCo and I&M.
RTO                                Regional Transmission Organization.
SEC                                Securities and Exchange Commission.
SFAS                               Statement of Financial Accounting Standards issued by the Financial Accounting Standards
                                            Board.
SFAS 71                            Statement of Financial Accounting Standards No. 71,
                                            Accounting for the Effects of Certain Types of Regulation.
                                            ---------------------------------------------------------
SFAS 101                           Statement of Financial Accounting Standards No. 101,
                                            Accounting for the Discontinuance of Application of Statement 71.
                                            ----------------------------------------------------------------
SFAS 133                           Statement of Financial Accounting Standards No. 133,
                                            Accounting for Derivative Instruments and Hedging Activities.
                                            ------------------------------------------------------------
SFAS 143                           Statement of Financial Accounting Standards No. 143,
                                            Accounting for Asset Retirement Obligations.
                                            -------------------------------------------
SFAS 149                           Statement of Financial Accounting Standards No. 149,
                                            Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
                                            ---------------------------------------------------------------------------
SFAS 150                           Statement of Financial Accounting Standards No. 150,
                                            Accounting for Certain Financial Instruments with Characteristics of both Liabilities
                                            -------------------------------------------------------------------------------------
                                            and Equity.
                                            ----------
SNF                                Spent Nuclear Fuel.
SPP                                Southwest Power Pool.
STP                                South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
                                            AEP electric utility subsidiary.
STPNOC                             STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
                                            its joint owners including TCC.
SWEPCo                             Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC                                AEP Texas Central Company, an AEP electric utility subsidiary.
Tenor                              Maturity of a contract.
Texas Legislation                  Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC                                AEP Texas North Company, an AEP electric utility subsidiary.
TVA                                Tennessee Valley Authority.
U.K.                               The United Kingdom.
VaR                                Value at Risk, a method to quantify risk exposure.
Virginia SCC                       Virginia State Corporation Commission.
WVPSC                              Public Service Commission of West Virginia.
WPCo                               Wheeling Power Company, an AEP electric distribution subsidiary.
Zimmer Plant                       William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
                                            Southern Power Company, an AEP subsidiary.
</TABLE>


<PAGE>

     FORWARD-LOOKING INFORMATION

     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 including requirements for
      reduced emissions of sulfur, nitrogen, carbon and other substances.
o   Pending and future rate cases and negotiations.
o   Oversight and/or investigation of the energy sector or its
      participants.
o   Our ability to successfully control costs.
o   The success of 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.
o   The economic climate and growth in our service territory and changes
      in market
      demand and demographic patterns.
o   Inflationary trends.
o   Accounting pronouncements periodically issued by accounting
      standard-setting bodies.
o   The performance of AEP's pension plan.
o   Electricity and gas market prices.
o   Interest rates.
o   Liquidity in the banking, capital and wholesale power markets.
o   Actions of rating agencies.
o   Changes in technology, including the increased use of distributed
      generation within our transmission and distribution service
      territory.
o   Other risks and unforeseen events, including wars, the effects of
      terrorism, embargoes and other catastrophic events.




<PAGE>

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

Results of Operations

American Electric Power Company's consolidated Net Income (Loss) by operating
segment for the third quarter and nine months ended September 30, 2003 and 2002
were as follows:

<TABLE>
<CAPTION>

                                                  Third Quarter                   Nine Months Ended
                                                  -------------                   -----------------
                                             2003             2002             2003             2002
                                             ----             ----             ----             ----
                                                                  (in millions)
<C>                                           <C>              <C>              <C>              <C>
Utility Operations                            $372             $405             $886             $846
Investments - Gas Operations                   (20)               5              (59)             (75)
Investments - UK Operations                    (51)              (5)             (88)               6
Investments - Other                            (44)             (19)             (44)             (74)
                                              -----            -----            -----            -----
Continuing Operations                          257              386              695              703

  Discontinued Operations                        -               39              (16)             (35)
   Cumulative Effect of
    Accounting Changes                           -               -               193             (350)
                                              -----            -----            -----            -----

Total Net Income                              $257             $425             $872             $318
                                              =====            =====            =====            =====
</TABLE>

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Our Net Income for the third quarter of 2003 is discussed below according to the
operating segments listed above. Income from Continuing Operations (or Income
Before Discontinued Operations and Cumulative Effect of Accounting Changes) for
the quarter was negatively affected by the weather, weak economy and the
availability of electric generation. Third quarter 2003 Net Income was $257
million or $0.65 per share compared to $425 million or $1.25 per share in 2002.
In March 2003 common stock was issued which caused $0.11 per share dilution in
the current quarter.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Our Net Income for Nine Months Ended is discussed below according to the
operating segments listed above. Income from Continuing Operations (or Income
Before Discontinued Operations and Cumulative Effect of Accounting Changes) was
negatively affected by the weather, weak economy and the availability of
electric generation. 2003 Net Income of $872 million or $2.28 per share includes
a loss on discontinued operations of $16 million (net of tax) (see Note 8), $242
million (net of tax) of Income from the Cumulative Effect of Accounting Changes
in the first quarter resulting from the implementation of SFAS 143 (see Note 3),
partially offset by $49 million (net of tax) of Loss from the Cumulative Effect
of Accounting Changes in the first quarter resulting from the implementation of
EITF 02-3 (see Note 3). 2002 Net Income of $318 million or $0.97 per share
includes a loss on discontinued operations of $35 million (net of tax) (see Note
8) and a $350 million (net of tax) charge for the implementation of SFAS 142
(see Note 3). A common stock issuance in March 2003 caused a $0.37 per share
dilution in the nine-month period.


Utility Operations

<TABLE>
<CAPTION>


                                                          Summary of Selected Sales Data
                                                             For Utility Operations

                                                  Third Quarter                   Nine Months Ended
                                                  -------------                   -----------------
                                              2003             2002            2003              2002
                                              ----             ----            ----              ----
                                                                (in millions of KWH)
ENERGY SUMMARY
Retail
<C>                                         <C>              <C>              <C>              <C>
  Residential                               12,606           13,405           34,813           35,781
  Commercial                                10,341           10,118           28,082           27,797
  Industrial                                12,932           13,154           38,620           40,287
  Miscellaneous                                829              891            2,258            2,059
                                            -------          -------         --------         --------
       Total                                36,708           37,568          103,773          105,924
                                            -------          -------         --------         --------
Wholesale                                   22,093           20,938           56,385           53,393
                                            -------          -------         --------         --------

WEATHER SUMMARY                                                     (in degree days)
EASTERN REGION
Actual - Heating                                78               22            3,444            2,910
Normal - Heating                                80               80            3,298            3,340

Actual - Cooling                               618              916              782            1,269
Normal - Cooling                               708              701            1,002              992

WESTERN REGION
Actual - Heating                                 -                -              839              789
Normal - Heating                                 -                -              840              829

Actual - Cooling                             1,386            1,438            1,941            2,063
Normal - Cooling                             1,398            1,396            1,919            1,910

</TABLE>

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Net Income for Utility Operations, our core business, decreased by $33 million
due to a decrease in operating income.

Our operating income decreased in the third quarter primarily due to:

o  A reduction in pre-tax earnings of $89 million for the loss of
   contributions from our two Texas retail electricity providers that we
   sold to Centrica in December 2002. The demand from our two Texas retail
   providers was replaced, in part, with a power supply contract with
   Centrica that extends through 2004. Our Texas supply margins also
   decreased due to an outage at our STP nuclear plant and the related
   higher costs of replacement power. Our 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  Retail margins from our regulated integrated utilities, which reduced
   pre-tax earnings by $71 million due to lower demand from the combined
   impact of weather and a continued weak economy.

o  Reduced demand in our Ohio Companies resulting from mild weather and
   economic pressures on industrial customers, which reduced pre-tax
   earnings by $15 million.

Our operating income decrease was partially offset by:

o  Pre-tax earnings from our Texas distribution operations (Texas wires),
   which increased $19 million primarily from the $61 million non-cash
   earnings associated with the capacity auction true-up in Texas. The
   provisions for stranded cost recovery in Texas recognize a regulatory
   asset or liability for the difference between the actual price received
   from the state-mandated auction of 15% of generation capacity and the
   earlier estimate of market price derived by a PUCT model. We filed a
   plan of divestiture with the PUCT in December 2002, enabling us to
   record a regulatory asset associated with stranded cost recovery. Our
   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, which increased $76 million in the
   current quarter due to low cost generation that was available because
   of weather-related reductions in retail demand, favorable power
   optimization and higher peak prices in ECAR.

o  A $13 million decrease in Taxes Other Than Income Taxes primarily
   caused by reduced gross receipts tax due to the sale of the Texas REPs.

o  A $15 million decrease in Maintenance and Other Operation expenses due
   to ongoing efforts to reduce costs despite incurring higher storm
   damage repair costs in the current quarter.


Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Net Income for Utility Operations increased $40 million due primarily to an $85
million increase in operating income partially offset by an increase in
nonoperating expenses.

Our operating income increased primarily due to:

o   Texas wires pre-tax  earnings,  which increased $137 million
    primarily from $169 million in non-cash  earnings  associated
    with the capacity auction true-up in Texas.

o   Pre-tax earnings for systems sales, transmission revenue and other
    wholesale transactions, which increased $141 million due to low cost
    generation that was available because of weather-related reductions in
    retail demand, favorable power optimization, higher peak prices and
    increased sales in ECAR. In addition, we experienced higher third-party
    transmission volumes and recognized a loss on the settlement of a
    long-term contract with the Public Utility District No. 1 of Snohomish
    County, Washington (see Significant Factors - Litigation).

o   Other operating revenue, which increased $29 million due to associated
    business development in Western non-regulated companies for the
    construction of transmission lines, services fees, pole attachments and
    transmission rentals.

o   Maintenance  and Other  Operation  expense,  which  decreased  $39
    million due to ongoing  efforts to reduce costs  despite severe storm
    damage in the Midwest.

o   A $28 million decrease in Taxes Other Than Income Taxes primarily
    caused by reduced gross receipts tax due to the sale of the Texas REPs.

o   Depreciation and Amortization, which decreased by $28 million due to
    the change in accounting for asset retirement obligations as mandated
    by SFAS 143. This decrease, however, is offset by similar increases in
    Maintenance and Other Operation expenses.

Our operating income increase was partially offset by:

o   Retail margins from our regulated integrated utilities, which reduced
    pre-tax earnings by $132 million due to the combined impacts of
    weather, a continued weak economy and replacement power costs
    associated with our Cook Plant outages.

o   Lower demand at our Ohio Companies, which reduced pre-tax earnings by
    $11 million. This reduced demand was attributable to mild weather and
    economic pressures on industrial customers.

o   A reduction in pre-tax earnings of $173 million for the loss of
    contributions from our two Texas retail electricity providers that we
    sold to Centrica in December 2002. The demand from our two Texas retail
    providers was replaced, in part, with a power supply contract with
    Centrica that extends through 2004. Our Texas supply margins also
    decreased due to an outage at our STP nuclear plant and a separate
    provision for potential disallowance by the PUCT of certain historical
    fuel expenses. Our Texas supply represents the gross margin for output
    of generating units in the ERCOT region and from "reliability must run"
    (RMR) contracts with ERCOT.


Investments - Gas Operations

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Net Loss from our Gas Operations, which includes Louisiana Intrastate Gas and
Houston Pipe Line operations, increased $25 million from the comparable quarter
in 2002 due to lower margins resulting from our reduced risk profile and MTM
gains recorded on contracts during the third quarter of 2002, which did not
recur during 2003. The increased loss was partially offset by reduced operating
expenses of $4 million.


Nine Months Ended September 30, 2003 Compared to Nine Months Ended  September
-----------------------------------------------------------------------------
30, 2002
--------

Net Loss from our Gas Operations of $59 million decreased $16 million from the
comparable period in 2002. We reduced Operating expenses by $22 million and
interest expense by $8 million. These favorable factors are partially offset by
reductions in margins resulting from our reduced risk profile and MTM gains,
which did not recur during 2003.


Investments - UK Operations

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Net Loss from our UK Operations, which includes Fiddler's Ferry and Ferrybridge
plants (FFF), increased by $46 million. During the third quarter, pre-tax gross
margins declined by $54 million driven by timing differences which result in
losses on coal and financial freight contracts that are marked-to-market and
that are not offset during the quarter by mark-to-market gains on physical
freight contracts because physical freight contracts are accounted for on a
settlement basis. Our net loss was also greater due to reduced trading activity
and weaker power trading margins. Operation and maintenance expense increased by
$14 million due to incentives, severance and corporate charges. The operating
loss in the current quarter was partially offset by reduced income taxes.


Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Net Loss from our UK Operations increased by $94 million due to the reductions
in operating income. During the period, pre-tax gross margins declined due to
timing differences in the accounting treatment for physical freight versus
hedging transactions noted above. Our net loss was also driven by increases in
operations and maintenance costs, which included severance and redundancy costs
of the Nordic trading office.


Investments - Other

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Net Loss from our Other investments, which consists of investments in
independent power plants, coal mines, river transportation, and communications,
was $44 million in the third quarter of 2003, an increase of $25 million over
the comparable quarter in 2002. During the third quarter of 2003, two of our
independent generation facilities became impaired and we recognized a loss of
$45 million. This loss was partially offset by favorable variances caused by the
2002 wind-down of our communications operations, a Vale impairment in 2002, and
2002 pre-tax losses for investments in Dynetec and Altra Energy, which did not
recur in 2003. AEP Pro Serv's (Pro Serv) operating margins decreased by $4
million during 2003 from the comparable quarter in 2002.


Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Net Loss from our Other investments decreased by $30 million due to lower
international development costs, reduced interest expense and lower costs to
wind-down operations. These decreases were partially offset by our impairment of
two of our independent generation facilities during 2003. Pro Serv's operating
margins decreased by $19 million during 2003 from the comparable period in 2002.


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 certain debt ratings.
The completion of these reviews was a culmination of rating actions started
during 2002.


Liquidity

At September 30, 2003, our liquidity sources totaled $4.6 billion and we had an
available liquidity position of $4.2 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                              351*               10/03
      Letter of Credit Facility                 200                 9/06
                                             -------
      Total                                   3,051
      Liquidity Reserves                        300**
      Other Temporary
                Investments                   1,234**
                                             -------
      Total Liquidity Sources                 4,585
      Less: Commercial Paper
                 Outstanding                    427
               Letter of Credit
                 Outstanding                      8

      Total Available Liquidity              $4,150
                                             =======

*   One of the Euro Revolving Credit Facilities has expired and has not been
    renewed. The remaining facility was renewed, for a one-year term, in the
    amount of 150 million (Euro) during October 2003.

**  Liquidity Reserves, Other Temporary Investments and $174 million of
    operational cash on hand make up the $1,708 million Cash and Cash
    Equivalents balance on our Consolidated Balance Sheet at September 30, 2003.
    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 reduced the quarterly common stock
dividend to $0.35 per share, which was a 42% decrease from the previous
dividend of $0.60 per share. This reduction will result in annual cash savings
of approximately $395 million.

Cash Flow
                                                           Nine Months Ended
                                                           2003         2002
                                                           ----         ----
                                                             (in millions)

    Cash and cash equivalents at beginning of period    $1,213          $224
                                                        -------        ------
    Net cash from (used for) continuing operations:
      Operating activities                               1,553           746
      Investing activities                                (885)          (19)
      Financing activities                                (173)         (397)
    Effect of exchange rate changes on cash and
     cash equivalents                                      -              (3)
                                                        -------        ------
    Net increase in cash and cash equivalents              495           327
                                                        -------        ------
    Cash and cash equivalents at end of period          $1,708          $551
                                                        =======        ======

Cash from operations, a bank-sponsored receivables purchase agreement 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 (through the agreement referenced above) to provide
liquidity for the domestic electric subsidiaries. Short-term borrowings are
supported by three revolving credit agreements.

Operating Activities

Cash flows from operating activities during the first nine months of 2003 were
$1,553 million. Beginning with Income Before Discontinued Operations and
Cumulative Effect of Accounting Changes of $695 million, we add depreciation,
amortization and deferred taxes of $1,334 million and deduct $169 million of
non-cash ECOM, $83 million in mark-to-market changes and $296 million for
working capital changes. The negative working capital changes include $90
million paid to Williams Companies in settlement for power and gas transactions,
and $59 million in increased fuel inventories.

Investing Activities

Cash flows used for investing activities during the first nine months of 2003
were $885 million compared to $19 million during 2002. The major reason for the
year-over-year variance was a construction expenditures reduction of $196
million in 2003 and proceeds of $1,116 million from the sale of assets in 2002.
The 2002 sale of assets was part of our plan to sell non-core investments and
improve our liquidity.

Total consolidated plant and property additions for the first nine months of
2003 were $941 million, including continued construction expenditures for
emission control technology at several coal-fired generating plants (see Note
6).

Financing Activities

Cash flows used for financing activities in the first nine months of 2003
decreased by $224 million compared to 2002, primarily as the result of AEP's
reduction in the common stock dividend. During the first nine months of 2003,
AEP retired $4,789 million of debt ($2,825 million short-term and $1,964 million
of long-term) and increased available cash primarily through the issuance of
long-term financing ($4,146 million), the issuance of common stock ($1,177
million) and the generation of cash from operating activities. Also, see Note 12
for further information on financing activities.

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

Possible Divestitures

We are firmly committed to continually evaluate the need to reallocate resources
to areas that effectively match our investments with our business strategy and
provide the greatest potential for financial returns. Similarly, we are
committed to disposing of investments that no longer meet these principles.

We are seeking to divest substantially all of our non-regulated assets including
domestic and international unregulated generation, gas pipelines, a coal
business, independent power producers (IPP) and a communications business. In
June 2003, we began actively seeking buyers for 4,497 megawatts of unregulated
generating capacity in Texas. The value received from this disposition will also
be used to calculate our stranded costs in Texas (see Note 5). We expect to
receive final bids in the fourth quarter of 2003.

During the second quarter of 2003, we also hired an advisor to evaluate our coal
business, which has resulted in receipt of non-binding bids. We are currently
evaluating these bids.

During the third quarter of 2003, management hired advisors to review business
options regarding various investment components of our Gas Operations. We
distributed an initial offering memorandum and request for proposal on the sale
of our Louisiana Intrastate Gas and Jefferson Island Storage Facility operations
in the fourth quarter of 2003.

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

During the fourth quarter of 2003, we selected an advisor for the disposition of
our UK business. We are evaluating the market for possible disposition of these
UK assets prior to our assumed date of year-end 2004.

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 sought regulatory 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. Further, legislation in some of our states
requires RTO participation.

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

In December 2002, our subsidiaries that operate in the states of Indiana,
Kentucky, Ohio and Virginia filed for state regulatory commission approval of
their plans to transfer functional control of their transmission assets to PJM.
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. In August 2003, AEP
sought and received rehearing of the KPSC's order, allowing us to file
additional evidence in this proceeding. In September 2003, the IURC issued an
order approving I&M's transfer of functional control over its transmission
facilities to PJM, subject to certain specified conditions. Proceedings in the
other states remain pending.

In February 2003, Virginia enacted legislation that prohibited the transfer of
transmission assets in its jurisdiction to an RTO until, at the earliest, July
2004 and only with the approval of Virginia SCC.

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.

If AEP East companies do not obtain regulatory approval to join PJM, we are
committed to reimburse PJM for certain project implementation costs (presently
estimated at $23 million for the entire PJM integration project). AEP also has
$24 million, at September 30, 2003, of deferred RTO formation/integration costs
for which we plan to seek recovery in the future. See Note 4 for further
discussion.

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

On September 29 and 30, 2003, the FERC held a public inquiry regarding RTO
formation, including delays in AEP's participation in PJM.

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

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 in various state regulatory
jurisdictions is presented in Note 5.

Restructuring legislation in Texas provides that the PUCT address several issues
in the 2004 true-up proceeding. One of these issues is the wholesale capacity
auction true-up. TCC has recorded $431 million of regulatory assets and related
revenues through September 30, 2003 based upon our estimate.

In July 2003, the PUCT Staff published their proposed filing package for the
2004 true-up proceeding. Within the filing package are instructions and sample
schedules that demonstrate the calculation of the wholesale capacity auction
true-up. That calculation differs from the methodology being employed by TCC.
TCC filed comments on the proposed 2004 true-up filing package in September 2003
and took exception to the methodology employed by the PUCT Staff. A true-up
filing package will probably be approved by the PUCT in the fourth quarter of
2003. If the PUCT Staff's methodology is approved, TCC's wholesale capacity
auction true-up regulatory asset could require adjustment.

In October 2003, a coalition of consumer groups (the Coalition of Ratepayers)
including the Office of Public Utility Counsel, the State of Texas, Cities
served by CPL and Texas Industrial Energy Consumers filed a petition with the
PUCT requesting that the PUCT initiate a rulemaking to amend the PUCT's stranded
cost true-up rule (True-up Rule). The Coalition of Ratepayers proposed to amend
the True-up Rule to revise the calculation of the wholesale capacity auction
true-up. If adopted, the Coalition of Ratepayers' proposal would substantially
reduce or possibly eliminate the wholesale capacity auction true-up regulatory
asset that TCC has accrued in 2002 and 2003. The PUCT requested that responses
to the Coalition of Ratepayers' petition be filed by November 7, 2003. On
November 5, 2003, the PUCT denied the Coalition of Ratepayers' petition.

See Notes 4 and 5 for further discussion.

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, wholesale capacity auction true-up regulatory assets,
other restructuring true-up items and costs, it could have a material adverse
effect on results of operations, cash flows and possibly financial condition.

Nuclear Plant Outages

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

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

Litigation

Federal EPA Complaint and Notice of Violation

As discussed 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 are involved in
litigation regarding generating plant emissions under the Clean Air Act. The
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. The 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 that 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 6 for further discussion.

NOx Reductions

The 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 other
combustion control 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 approximately $1 billion has been spent through
September 30, 2003. The actual cost to comply could be significantly different
than these 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, these
costs would adversely affect future results of operations, cash flows and
possibly financial condition. See Note 6 for further discussion.

Enron Bankruptcy

In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of 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. We also have various HPL related
contingencies and indemnities from Enron including issues related to the
underground Bammel gas storage facility and the cushion gas (pad gas) required
for its normal operation.

In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES
challenging AEP's offsetting of receivables and payables and related collateral
across various Enron entities and seeking payment of approximately $125 million
plus interest. We will assert our right to offset trading payables owed to
various Enron entities against trading receivables due to several AEP
subsidiaries. Management is unable to predict the ultimate resolution of these
issues or their impact on results of operations, cash flows and financial
condition. See Note 6 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 the appropriate trading
contract and industry practice in calculating termination and liquidation
amounts and that BOM had acknowledged just prior to the termination and
liquidation that it owed us approximately $68 million. We are claiming that BOM
owes us 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 settlement amount approximated the amount payable that, in the
ordinary course of business, we recorded as part of our trading activity using
MTM accounting. As a result, the resolution of this matter had an immaterial
impact on results of operations and financial condition. See Note 6 for further
discussion.

Arbitration of PG&E Energy Trading, LLC Claim

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

Energy Market Investigations

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 (CFTC), the U.S. Department
of Justice and the California attorney general during 2002. Management responded
to the inquiries and provided the requested information and has continued to
respond to supplemental data requests in 2003.

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

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

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

Shareholders' Litigation

In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against us, certain
executives, members of the Board of Directors and certain investment banking
firms. We intend to vigorously defend against these actions. See Note 6 for
further discussion.

California Lawsuit

In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. AEP has been dismissed
from the case. See Note 6 for further discussion.

Cornerstone Lawsuit

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

Texas Commercial Energy, LLP Lawsuit

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit against us and
four AEP subsidiaries, certain unaffiliated energy companies and ERCOT alleging
violations of the Sherman Antitrust Act, fraud, negligent misrepresentation,
breach of fiduciary duty, breach of contract, civil conspiracy and negligence.
The allegations, not all of which are made against the AEP companies, range from
anticompetitive bidding to withholding power. TCE alleges that these activities
resulted in price spikes requiring TCE to post additional collateral and
ultimately forced it into bankruptcy when it was unable to raise prices to its
customers due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary damages and
court costs. Management believes that the claims against us are without merit.
We intend to vigorously defend against the claims. See Note 6 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. The settlement amount was
less than the amount receivable that, in the ordinary course of business, we
recorded as part of our trading activity using MTM accounting. As a result, we
incurred 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 3 for a discussion of 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 (Liabilities)

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 (Liabilities)
                                                     Nine Months Ended September 30, 2003


                                                                    Utility          Gas               UK
                                                                  Operations      Operations       Operations       Consolidated
                                                                  ----------      ----------       ----------       ------------
                                                                                        (in millions)
        <C>                                                           <C>            <C>              <C>               <C>
        Beginning Balance December 31, 2002                           $360           $(155)           $ 45              $250
        (Gain) Loss from Contracts  Realized/Settled
         During  the Period (a)                                       (118)            122              16                20
        Fair Value of New Contracts When Entered
         Into During the Period (b)                                      -               -               -                 -
        Net Option Premiums Paid/(Received) (c)                          1              32             (12)               21
        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)                                                  42              39             (45)               36
        Changes in Fair Value of Risk Management  Contracts
        Allocated to Regulated  Jurisdictions (e)
                                                                         4               -               -                 4
                                                                      -----          ------           -----             -----
        Ending Balance September 30, 2003                             $270             $40            $(10)             $300
                                                                      =====          ======           =====             =====

</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 (Liabilities)
                                                        As of September 30, 2003

                                                                  Utility           Gas               UK
                                                                 Operations      Operations       Operations     Consolidated
                                                                 ----------      ----------       ----------     ------------
                                                                                        (in millions)
        <C>                                                          <C>            <C>               <C>             <C>
        Current Assets                                                $300           $297              $362              $959
        Non Current Assets                                             376            186               247               809
                                                                     ------         ------            ------          --------
        Total MTM Risk Management Contract Assets                     $676          $ 483              $609           $ 1,768
                                                                     ------         ------            ------          --------

        Current Liabilities                                          $(198)         $(214)            $(420)          $  (832)
        Non Current Liabilities                                       (208)          (229)             (199)             (636)
                                                                     ------         ------            ------          --------

        Total MTM Risk Management Contract  Liabilities              $(406)         $(443)            $(619)          $(1,468)
                                                                     ------         ------            ------          --------

        Total MTM Risk Management Contract  Net Assets
        (Liabilities)                                                $ 270            $40              $(10)              300
                                                                     ======         ======            ======          ========

        Net Non-Trading Related Derivative Contracts                                                                     (288)
                                                                                                                      --------
        Risk Management and Derivative Contract Net Assets                                                                $12
                                                                                                                      ========

</TABLE>

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

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

<TABLE>
<CAPTION>


                                                  Maturity and Source of Fair Value of MTM
                                             Risk Management Contract Net Assets (Liabilities)
                                              Fair Value of Contracts as of September 30, 2003

                                              Remainder                                                           After
                                                2003         2004          2005          2006         2007        2007      Total
                                                ----         ----          ----          ----         ----        ----      -----
                                                                                  (in millions)
<C>                                             <C>          <C>           <C>           <C>           <C>        <C>       <C>
Utility Operations:
Prices Actively Quoted - Exchange Traded
Contracts                                        $(5)        $(15)         $(3)          $(1)           $-         $-       $(24)
Prices   Provided by Other External
 Sources - OTC Broker Quotes (a)                  (1)         101           27            22             5          -        154
Prices Based on   Models   and Other
 Valuation Methods (b)                            28           23           (6)           21            24         50        140
                                                -----        -----         ----          ----          ----       ----      -----
Total                                            $22         $109          $18           $42           $29        $50       $270
                                                =====        =====         ====          ====          ====       ====      =====

Gas Operations:
Prices Actively Quoted - Exchange
 Traded Contracts                               $(64)         $96           $8            $-           $ -        $ -        $40
Prices Provided by Other External Sources
- OTC Broker Quotes (a)                           27          (12)           1             -             -          -         16
Prices Based on Models and Other
 Valuation Methods (b)                           (15)          15           (3)           (6)            1         (8)       (16)
                                                -----        -----         ----          ----          ----       ----      -----
Total                                           $(52)         $99           $6           $(6)           $1        $(8)       $40
                                                =====        =====         ====          ====          ====       ====      =====

UK Operations:
Prices Actively  Quoted - Exchange Traded
Contracts                                         $-           $-          $ -            $-            $-         $-         $-
Prices Provided by Other External Sources
- OTC Broker Quotes (a)                           43          (50)          15            (7)           (2)         -         (1)
Prices Based on Models and Other
 Valuation Methods (b)                            (7)                        -            (1)           (1)         -         (9)
                                                -----        -----         ----          ----          ----       ----      -----
Total                                            $36         $(50)         $15           $(8)          $(3)        $-       $(10)
                                                =====        =====         ====          ====          ====       ====      =====

Consolidated:
Prices Actively Quoted - Exchange Traded
Contracts                                       $(69)         $81           $5           $(1)           $-         $-        $16
Prices Provided by Other External Sources
- OTC Broker Quotes (a)                           69           39           43            15             3          -        169
Prices Based on Models and Other
 Valuation Methods (b)                             6           38           (9)           14            24         42        115
                                                -----        -----         ----          ----          ----       ----      -----
Total                                             $6         $158          $39           $28           $27        $42       $300
                                                =====        =====         ====          ====          ====       ====      =====

</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 September 30, 2003

                                                                                                              Tenor
        Domestic                                                                                            (in months)
        --------                                                                                            -----------

        <C>                 <C>                                  <C>                                             <C>
        Natural Gas         Forward Purchases and Sales
                                                                 NYMEX Henry Hub Gas                             72
                                                                 Gas East - Northeast, Mid-continent
                                                                  Gulf Coast, Texas                              25

                                                                 Gas West - Permian Basin, San Juan,
                                                                  Rocky Mtns, Kern, Cdn
                                                                  Border (Sumas),
                                                                  Malin, PGE Citygate, AECO                      25
                            Over the Counter Options                                                             13

        Power (Peak)        Forward Purchases and Sales
                                                                 Power East - Cinergy                            27
                                                                 Power East - PJM                                39
                                                                 Power East - NYPP                               27
                                                                 Power East - NEPOOL                             27
                                                                 Power East - ERCOT                              15
                                                                 Power East - TVA                                 0
                                                                 Power East - Com Ed                              7
                                                                 Power East - Entergy                            15
                                                                 Power West - PV,  NP15, SP15, MidC, Mead
                                                                                                                 51
                            Peak Power Volatility
                             (Options)                           Cinergy                                         15
                            OffPeak Power Volatility             All Regions                                      0

        Natural Gas
         Liquids                                                                                                 14

        WTI Crude                                                                                                48

        Emissions                                                                                                27

        Coal                                                                                                     27

        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 is exposed to market fluctuations in energy commodity prices impacting its
power operations. AEP monitors these risks on its future operations and may
employ various commodity instruments as cash flow hedges to mitigate the impact
of these fluctuations on the future cash flows from its assets. AEP dos not
hedge all commodity price risk.


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.

<TABLE>
<CAPTION>

                                Cash Flow Hedges included in Accumulated Other Comprehensive Income (Loss)
                                             On the Balance Sheet as of September 30, 2003

                                                                                               Portion Expected to
                                                                     Accumulated Other         Be Reclassified to
                                                                   Comprehensive Income        Earnings During the
                                                                    (Loss) After Tax (a)        Next 12 Months (b)
                                                                   ---------------------       -------------------
                                                                                     (in millions)

        <C>                                                                <C>                        <C>
        Power                                                              $(172)                     $(83)
        Foreign Currency                                                     (10)                       (8)
        Interest Rate                                                        (11)                       (5)
                                                                           ------                     -----
        AEP Consolidated                                                   $(193)                     $(96)
                                                                           ======                     =====

</TABLE>

<TABLE>
<CAPTION>

                                                Total Other Comprehensive Income Activity
                                                   Nine Months Ended September 30, 2003

                                                                        Foreign                            AEP
                                                         Power          Currency    Interest Rate     Consolidated
                                                         -----          --------    -------------     ------------
                                                                              (in millions)
        <C>                                              <C>             <C>             <C>               <C>
        Accumulated OCI,
         December 31, 2002                                $ (3)           $(1)           $(12)             $ (16)
        Changes in Fair Value (c)                         (171)            (9)              3               (177)
        Reclassifications from OCI to Net
         Income (d)                                          2              -              (2)                 -
                                                         ------          -----           -----             ------
        Accumulated OCI Derivative Loss September
         30, 2003                                        $(172)          $(10)           $(11)             $(193)
                                                         ======          =====           =====             ======

</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 items affecting net income. Amounts are reported net of related
          income taxes.
(d)       Reclassifications from AOCI to net income - Gains or losses from
          derivatives used as hedging instruments in cash flow hedges that were
          reclassified into net income during the reporting period. Amounts are
          reported net of related income taxes above.

Credit Risk

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 September 30, 2003. At September 30, 2003, AEP's credit exposure
net of credit collateral to sub investment grade counterparties was
approximately 11%, expressed in terms of net MTM assets and net receivables. As
of September 30, 2003, the following table approximates counterparty credit
quality and exposure for AEP based on netting across AEP commodities and
instruments:

<TABLE>
<CAPTION>

                                                                                                 Number of          Net Exposure of
        Counterparty                       Exposure Before          Credit            Net      Counterparties       Counterparties
        Credit Quality:                    Credit Collateral      Collateral       Exposure         > 10%                > 10%
        --------------                     -----------------      ----------       --------    --------------       ---------------
                                                                                 (in millions)
        <C>                                       <C>                <C>            <C>                <C>                   <C>
        Investment Grade                          $1,002             $ 32           $  970             2                     $243
        Split Rating                                  27               -                27             1                       27
        Non-Investment Grade                         169               96               73             3                       29
        No External Ratings:
          Internal Investment
            Grade                                    292                7              285             1                       90
          Internal Non-Investment
            Grade                                    128               50               78             1                       10
                                                  -------            -----          -------            -                     -----
        Total                                     $1,618             $185           $1,433             8                     $399
                                                  =======            =====          =======            =                     =====

</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 September 30, 2003

                                               2003       2004        2005
                                               ----       ----        ----
Estimated Plant Output Hedged (a)               94%        92%         84%

(a)       Estimated Plant Output Hedged - Represents the portion of
          megawatt-hours of future generation/production for which AEP has
          sales commitments or estimated requirements obligations 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 and a one-day
holding period. Based on this VaR analysis, at September 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

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

             $7    $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.

<TABLE>
<CAPTION>

                                                                    CCRO VaR Metrics
                                                             Average for
                                            End of          Year-to-Date              High for             Low for
                                     September 30,  2003        2003            Year-to-Date  2003     Year-to-Date 2003
                                     -------------------    ------------        ------------------     -----------------
                                                                     (in millions)
<C>                                         <C>                 <C>                    <C>                    <C>
95% Confidence Level, Ten-Day
  Holding Period                            $28                 $26                    $71                    $17

99% Confidence Level, One-Day
  Holding Period                            $12                 $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 and a one-year holding period. The volatilities and
correlations were based on three years of daily prices. The risk of potential
loss in fair value attributable to AEP's exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $1,156 million at
September 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 our 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
                                      For the Three and Nine Months Ended September 30, 2003 and 2002
                                                 (in millions, except per-share amounts)
                                                              (Unaudited)

                                                                                Three Months Ended               Nine Months Ended
                                                                              2003           2002             2003           2002
                                                                              ----           ----             ----           ----
                               REVENUES
----------------------------------------------------------------------
<C>                                                                          <C>           <C>               <C>            <C>
Utility Operations                                                           $3,111        $2,940            $8,512         $7,858
Gas Operations                                                                  860           700             2,791          1,803
U.K. Operations and Other                                                       138           171               555            723
                                                                             -------       -------           -------        -------
TOTAL                                                                         4,109         3,811            11,858         10,384
                                                                             -------       -------           -------        -------
                               EXPENSES
----------------------------------------------------------------------
Fuel for Electric Generation                                                    916           666             2,426          1,918
Purchased Electricity for Resale                                                206           306               626            413
Purchased Gas for Resale                                                        828           625             2,685          1,691
Maintenance and Other Operation                                                 977           868             2,921          3,073
Depreciation and Amortization                                                   334           362               985          1,045
Taxes Other Than Income Taxes                                                   179           202               524            576
                                                                             -------       -------           -------        -------
TOTAL                                                                         3,440         3,029            10,167          8,716
                                                                             -------       -------           -------        -------

OPERATING INCOME                                                                669           782             1,691          1,668
                                                                             -------       -------           -------        -------

Other Income                                                                     75           115               279            176
                                                                             -------       -------           -------        -------

                       INTEREST AND OTHER CHARGES
----------------------------------------------------------------------
Investment Value and Other Impairment Losses                                     70             -                70              -
Other Expense                                                                    51            75               153            101
Interest                                                                        217           181               620            572
Preferred Stock Dividend Requirements of Subsidiaries                             1             3                 7              8
Minority Interest in Finance Subsidiary                                           -             9                17             27
                                                                             -------       -------           -------        -------
TOTAL                                                                           339           268               867            708
                                                                             -------       -------           -------        -------

INCOME BEFORE INCOME TAXES                                                      405           629             1,103          1,136
Income Taxes                                                                    148           243               408            433
                                                                             -------       -------           -------        -------
INCOME BEFORE DISCONTINUED OPERATIONS AND  CUMULATIVE EFFECT                    257           386               695            703
Discontinued Operations (net of tax)                                              -            39               (16)           (35)


         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                                                                     $257          $425              $872           $318
                                                                             =======       =======           =======        =======


AVERAGE NUMBER OF SHARES OUTSTANDING                                            395           339               382            329
                                                                             =======       =======           =======        =======

                     EARNINGS (LOSS) PER SHARE
----------------------------------------------------------------------
Income Before Discontinued Operations And Cumulative Effect
  of Accounting Changes                                                       $0.65         $1.14             $1.81          $2.14
Discontinued Operations                                                           -          0.11             (0.04)         (0.10)
Cumulative Effect of Accounting Changes                                           -             -              0.51          (1.07)
                                                                             -------       -------           -------        -------
TOTAL EARNINGS PER SHARE (BASIC AND DILUTIVE)                                 $0.65         $1.25             $2.28          $0.97
                                                                             =======       =======           =======        =======

CASH DIVIDENDS PAID PER SHARE                                                 $0.35         $0.60             $1.30          $1.80
                                                                             =======       =======           =======        =======
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>
<TABLE>
<CAPTION>

                                    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                   CONSOLIDATED BALANCE SHEETS
                                                             ASSETS
                                            September 30, 2003 and December 31, 2002
                                                           (Unaudited)

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

                             CURRENT ASSETS
----------------------------------------------------------------------------------
<C>                                                                                        <C>                    <C>
Cash and Cash Equivalents                                                                  $1,708                 $1,213
Accounts Receivable (net)                                                                   1,535                  1,740
Fuel, Materials and Supplies                                                                1,197                  1,166
Risk Management Assets                                                                      1,014                  1,012
Other                                                                                         901                    935
                                                                                          --------               --------
TOTAL                                                                                       6,355                  6,066
                                                                                          --------               --------

                        PROPERTY, PLANT AND EQUIPMENT
----------------------------------------------------------------------------------
Electric:
   Production                                                                              18,616                 17,031
   Transmission                                                                             6,099                  5,882
   Distribution                                                                             9,815                  9,573
Other (including gas, coal mining and nuclear fuel)                                         3,997                  3,965
Construction Work in Progress                                                                 973                  1,406
                                                                                          --------               --------
TOTAL                                                                                      39,500                 37,857
Less: Accumulated Depreciation and Amortization                                            16,488                 16,173
                                                                                          --------               --------
TOTAL-NET                                                                                  23,012                 21,684
                                                                                          --------               --------

                         OTHER NON-CURRENT ASSETS
----------------------------------------------------------------------------------
Regulatory Assets                                                                           2,612                  2,688
Securitized Transition Assets                                                                 703                    735
Investments in Power and Distribution Projects                                                221                    283
Goodwill                                                                                      397                    396
Assets Held for Sale                                                                          194                    277
Assets of Discontinued Operations                                                               -                     15
Long-term Risk Management Assets                                                              818                    819
Other                                                                                       1,767                  1,783
                                                                                          --------               --------
TOTAL                                                                                       6,712                  6,996
                                                                                          --------               --------

TOTAL ASSETS                                                                              $36,079                $34,746
                                                                                          ========               ========
</TABLE>

See Notes to Consolidated Financial Statements.


<PAGE>
<TABLE>
<CAPTION>


                                  AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                   CONSOLIDATED BALANCE SHEETS
                                               LIABILITIES AND SHAREHOLDERS' EQUITY
                                             September 30, 2003 and December 31, 2002
                                                          (Unaudited)

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

                             CURRENT LIABILITIES
---------------------------------------------------------------------------------------
<C>                                                                                               <C>                   <C>
Accounts Payable                                                                                  $1,700                $2,030
Short-term Debt                                                                                      443                 3,164
Long-term Debt Due Within One Year                                                                 1,234                 1,633
Risk Management Liabilities                                                                        1,029                 1,113
Other                                                                                              1,782                 1,802
                                                                                                 --------              --------
TOTAL                                                                                              6,188                 9,742
                                                                                                 --------              --------

                           NON-CURRENT LIABILITIES
---------------------------------------------------------------------------------------
Long-term Debt                                                                                    12,323                 8,487
Equity Unit Senior Notes                                                                             376                   376
Long-term Risk Management Liabilities                                                                791                   481
Deferred Income Taxes                                                                              4,144                 3,916
Deferred Investment Tax Credits                                                                      431                   455
Deferred Credits and Regulatory Liabilities                                                          837                   770
Deferred Gain on Sale and Leaseback -  Rockport Plant Unit 2                                         178                   185
Liabilities Held for Sale                                                                             98                   130
Liabilities of Discontinued Operations                                                                 -                    12
Other                                                                                              2,111                 1,903
Commitments and Contingencies (Note 6)
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption                           83                    -
                                                                                                 --------              --------
TOTAL                                                                                             21,372                16,715
                                                                                                 --------              --------

TOTAL LIABILITIES                                                                                 27,560                26,457
                                                                                                 --------              --------

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

                         COMMON SHAREHOLDERS' EQUITY
---------------------------------------------------------------------------------------
Common Stock-Par Value $6.50:
                                         2003          2002
                                         ----          ----
Shares Authorized. . . . . . . . . . .600,000,000   600,000,000
Shares Issued. . . . . . . . . . . . .404,004,712   347,835,212
(8,999,992 shares were held in treasury at  September 30, 2003 and December 31, 2002)              2,626                 2,261
Paid-in Capital                                                                                    4,184                 3,413
Accumulated Other Comprehensive Income (Loss)                                                       (745)                 (609)
Retained Earnings                                                                                  2,393                 1,999
                                                                                                 --------              --------
TOTAL                                                                                              8,458                 7,064
                                                                                                 --------              --------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                                       $36,079               $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
                                       For the Nine Months Ended September 30, 2003 and 2002
                                                           (Unaudited)

                                                                                                        2003             2002
                                                                                                        ----             ----
                                                                                                             (in millions)
                                  OPERATING ACTIVITIES
-------------------------------------------------------------------------------------
<C>                                                                                                   <C>              <C>
Net Income                                                                                              $872             $318
Plus:  Discontinued Operations                                                                            16               35
                                                                                                      -------          -------
Income from Continuing Operations                                                                        888              353
Adjustments for Noncash Items:
    Depreciation and Amortization                                                                        984            1,066
    Deferred Income Taxes                                                                                256              (81)
    Deferred Investment Tax Credits                                                                      (24)             (21)
    Cumulative Effect of Accounting Changes                                                             (193)             350
    Impairments                                                                                           46                -
    Amortization of Deferred Property Taxes                                                               88               73
    Amortization of Cook Plant Restart Costs                                                              30               30
    Mark to Market of Risk Management Contracts                                                          (83)             217
Changes in Certain Current Assets and Liabilities:
    Accounts Receivable, net                                                                             176             (868)
    Fuel, Materials and Supplies                                                                         (59)            (176)
    Accrued Utility Revenues                                                                              70             (255)
    Prepayments and Other                                                                                (37)            (387)
    Accounts Payable                                                                                    (400)             771
    Taxes Accrued                                                                                        (34)             126
    Interest Accrued                                                                                      30              107
Over/Under Fuel Recovery                                                                                 131              (57)
Change in Other Assets                                                                                  (224)            (373)
Change in Other Liabilities                                                                              (92)            (129)
                                                                                                      -------          -------
Net Cash Flows From Operating Activities                                                               1,553              746
                                                                                                      -------          -------

                                  INVESTING ACTIVITIES
-------------------------------------------------------------------------------------
Construction Expenditures                                                                               (941)          (1,137)
Proceeds from Sale of Assets                                                                              49            1,116
Other                                                                                                      7                2
                                                                                                      -------          -------
Net Cash Flows Used For Investing Activities                                                            (885)             (19)
                                                                                                      -------          -------

                                  FINANCING ACTIVITIES
-------------------------------------------------------------------------------------
Issuance of Common Stock                                                                               1,177              656
Issuance of Long-term Debt                                                                             4,146            1,819
Issuance of Equity Unit Senior Notes                                                                       -              334
Change in Short-term Debt, net                                                                        (2,825)            (806)
Retirement of Long-term Debt                                                                          (1,964)          (1,800)
Retirement of Preferred Stock                                                                             (2)             (10)
Retirement of Minority Interest                                                                         (225)              -
Dividends Paid on Common Stock                                                                          (480)            (590)
                                                                                                      -------          -------
Net Cash Flows Used For Financing Activities                                                            (173)            (397)
                                                                                                      -------          -------

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


Net Increase in Cash and Cash Equivalents                                                                495              327
Cash and Cash Equivalents at Beginning of Period                                                       1,213              224
                                                                                                      -------          -------
Cash and Cash Equivalents at End of Period                                                            $1,708             $551
                                                                                                      =======          =======

Net Decrease in Cash and Cash Equivalents from Discontinued Operations                                   $(1)            $(25)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period                               8              108
                                                                                                      -------          -------
Cash and Cash Equivalents from Discontinued Operations - End  of Period                                   $7              $83
                                                                                                      =======          =======
</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $542 million and $555
million and for income taxes was $156 million and $242 million in 2003 and 2002,
respectively. Noncash acquisitions under capital leases were $9 million in 2003
and $1 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)
                                                               (in millions)
                                                                (Unaudited)

                                                                                                      Accumulated
                                                                                                         Other
                                                              Common      Paid-in       Retained      Comprehensive
                                                              Stock       Capital       Earnings      Income (Loss)         Total
                                                              -----       -------       --------      -------------         -----
<C>                                                           <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                                                                      (590)                            (590)
Other                                                                         (80)            15                              (65)
                                                                                                                           -------
TOTAL                                                                                                                       8,250
                                                                                                                           -------

              COMPREHENSIVE INCOME (LOSS)
-----------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
     Foreign Currency Translation Adjustments                                                                 97               97
     Unrealized Gains on Cash Flow Hedges                                                                      4                4
     Unrealized Losses on Securities Available for Sale                                                       (3)              (3)
NET INCOME                                                                                   318                              318
                                                                                                                           -------
TOTAL COMPREHENSIVE INCOME                                                                                                    416
                                                              -------      -------        -------          ------          -------
SEPTEMBER 30, 2002                                            $2,261       $3,394         $3,039           $ (28)          $8,666
                                                              =======      =======        =======          ======          =======


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

Issuance of Common Stock                                         365          812                                           1,177
Common Stock Dividends                                                                      (480)                            (480)
Common Stock Expense                                                          (36)                                            (36)
Other                                                                          (5)             2                               (3)
                                                                                                                           -------
TOTAL                                                                                                                       7,722
                                                                                                                           -------

              COMPREHENSIVE INCOME (LOSS)
-----------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
      Foreign Currency Translation Adjustments                                                                25               25
      Unrealized Losses on Cash Flow Hedges                                                                 (177)            (177)
      Unrealized Gains on Securities Available for Sale                                                        1                1
      Minimum Pension Liability                                                                               15               15
NET INCOME                                                                                   872                              872
                                                                                                                           -------
TOTAL COMPREHENSIVE INCOME                                                                                                    736
                                                              -------      -------        -------          ------          -------
SEPTEMBER 30, 2003                                            $2,626       $4,184         $2,393           $(745)          $8,458
                                                              =======      =======        =======          ======          =======
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>




         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                     SCHEDULE OF CONSOLIDATED LONG-TERM DEBT
                    September 30, 2003 and December 31, 2002
                                   (Unaudited)



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

TOTAL LONG-TERM DEBT OUTSTANDING
First Mortgage Bonds                         $1,247                $1,884
Installment Purchase Contracts                1,937                 1,680
Notes Payable                                   323                   520
Senior Unsecured Notes                        8,171                 4,819
Junior Debentures                                 -                   205
Securitization Bonds                            746                   797
Notes Payable to Caddis                         527                     -
Notes Payable to Trust                          321                     -
Other Long-term Debt                            358                   247
Unamortized Discount (net)                      (73)                  (32)
                                            --------               -------

TOTAL                                        13,557                10,120
Less Portion Due Within One Year              1,234                 1,633
                                            --------               -------

TOTAL LONG-TERM PORTION                     $12,323                $8,487
                                            ========               =======


<PAGE>


          AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                   (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 increased by $41 million and
     decreased by $8 million and UK Operations and Other revenues increased
     by $2 million and decreased by $11 million for the three and nine month
     periods ended September 30, 2002, respectively. Fuel for Electric
     Generation decreased by $16 million and $60 million and Purchased Gas
     for Resale decreased by $51 million and $213 million for the three and
     nine month periods ended September 30, 2002, respectively. Expenses for
     Maintenance and Other Operation increased by $105 million and $235
     million and Taxes Other Than Income Taxes increased by $5 million and
     $19 million for the three and nine month periods ended September 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
     -------------------------------

     Accumulated Other Comprehensive Income

     We expect to reclassify approximately $96 million of net losses from
     cash flow hedges in Accumulated Other Comprehensive Income (Loss) at
     September 30, 2003 to net income during the next twelve months at the
     time the hedged transactions affect net income. Seven years approximates
     the maximum period over which an exposure to a variability in future
     cash flows is hedged; less than 2% have a term longer than seven years.
     The actual amounts that we reclassify from Accumulated Other Comprehensive
     Income to Net Income can differ due to market price changes.

3.   NEW ACCOUNTING PRONOUNCEMENTS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES
     -------------------------------------------------------------------------

     FIN 46 "Consolidation of Variable Interest Entities"

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

     On July 1, 2003, we deconsolidated Caddis Partners, LLC (Caddis), which
     included amounts previously reported as Minority Interest in Finance
     Subsidiary ($759 million at December 31, 2002 and $533 million at June
     30, 2003). As a result, a note payable to Caddis is reported as a
     component of Long-Term Debt ($527 million at September 30, 2003). See
     Note 11 "Minority Interest in Finance Subsidiary" for further
     disclosures.

     On July 1, 2003, we also deconsolidated the trusts which hold
     mandatorily redeemable trust preferred securities. Therefore, $321
     million, previously reported as Certain Subsidiary Obligated,
     Mandatorily Redeemable, Preferred Securities of Subsidiary Trusts
     Holding Solely Junior Subordinated Debentures of Such Subsidiaries, is
     now reported as Notes Payable to Trust and is included in Long-term
     Debt.

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

     Effective July 1, 2003, OPCo consolidated JMG Funding, LP (JMG). Upon
     consolidation, OPCo recorded the assets and liabilities of JMG ($469.6
     million). OPCo now records the depreciation, interest and other
     operating expenses of JMG and eliminates JMG's revenues against OPCo's
     operating lease expenses. There is no cumulative effect of an accounting
     change recorded as a result of our requirement to consolidate JMG, and
     there is no change in net income due to the consolidation of JMG. See
     Note 10 "Leases" for further disclosures.

     SFAS 143 "Accounting for Asset Retirement Obligations"

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

     We completed a review of our asset retirement obligations and concluded
     that we have related legal liabilities for nuclear decommissioning costs
     for our Cook Plant and our partial ownership in the South Texas Project,
     as well as liabilities for the retirement of certain ash ponds, wind
     farms, the U.K. Plants, and certain coal mining facilities. Since we
     presently recover our nuclear decommissioning costs in our regulated
     cash flow and have existing balances recorded for such nuclear
     retirement obligations, we recognized the cumulative difference between
     the amount already provided through rates and the amount as measured by
     applying SFAS 143 as a regulatory asset or liability. Similarly, a
     regulatory asset was recorded for the cumulative effect of certain
     retirement costs for ash ponds related to our regulated operations. In
     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 operating companies have now been
     deregulated 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 September 30, 2003
     and December 31, 2002.


     The net favorable cumulative effect of the change in accounting
     principle for the nine months ended September 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 (in millions):
<TABLE>
<CAPTION>

                                                                                        U.K.
                                                                                       Plants,
                                                                                        Wind
                                                                                        Mills
                                               Nuclear                Ash             and Coal
                                           Decommissioning           Ponds           Operations         Total
                                           ---------------           -----           ----------         -----
     <C>                                        <C>                  <C>                <C>             <C>
     Asset Retirement Obligation
       Liability at
       January 1, 2003                          $718.3               $69.8              $37.2           $825.3
     Accretion expense                            39.1                 4.2                1.6             44.9
     Liabilities incurred                            -                   -                8.3              8.3
     Foreign currency
       translation                                   -                   -                3.5              3.5
                                                -------              ------             ------          -------

     Asset Retirement Obligation
       Liability at
       September 30, 2003                       $757.4               $74.0              $50.6           $882.0
                                                =======              ======             ======          =======
</TABLE>


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

     As of September 30, 2003 and December 31, 2002, the fair value of assets
     that are legally restricted for purposes of settling the nuclear
     decommissioning liabilities totaled $800 million and $716 million,
     respectively, recorded in Other Assets on our Consolidated Balance
     Sheets.

     Pro forma net income and earnings per share are not presented for the
     quarter ended September 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 during 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. 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
     also eliminated the recognition of physical inventories at fair value
     other than as provided by GAAP. We have implemented this standard for
     all physical inventory and non-derivative energy trading transactions
     occurring on or after October 25, 2002. For physical inventory and
     non-derivative energy trading transactions entered into prior to October
     25, 2002, we implemented this standard on January 1, 2003 and reported
     the effects of implementation as a cumulative effect of an accounting
     change. We recorded a $49 million after tax loss in net income as
     Accounting for Risk Management Contracts in our Consolidated Statements
     of Operations in Cumulative Effect of Accounting Changes ($12 million in
     Utility Operations, $22 million in Investments - Gas Operations and $15
     million in Investments - UK Operations segments).

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

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

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

     We implemented SFAS 150 effective July 1, 2003. SFAS 150 is the 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.

     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 SFAS 150,
     any measurement change for these liabilities is to be reported as the
     cumulative effect of a change in accounting principle.

     Beginning with our third quarter 2003 financial statements, $83 million
     of mandatorily redeemable Cumulative Preferred Stocks of Subsidiaries is
     now presented as Cumulative Preferred Stocks of Subsidiaries Subject to
     Mandatory Redemption, a component of Non-Current Liabilities on the
     consolidated balance sheets. Beginning July 1, 2003, dividends on these
     mandatorily redeemable preferred shares are now classified as interest
     expense on the consolidated statements of operations. In accordance with
     SFAS 150, dividends from prior periods remain classified as preferred
     stock dividends (a component of Preferred Stock Dividend Requirements of
     Subsidiaries).

     SFAS 142 "Goodwill and Other Intangible Assets"

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

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

     In November 2002, the FASB issued FIN 45 which clarifies the accounting
     to recognize a liability related to issuing a guarantee, as well as
     additional disclosures of guarantees. This 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 are effective
     on a prospective basis for guarantees issued or modified after December
     31, 2002. The disclosure requirements of FIN 45 are effective for
     financial statements of interim or annual periods ending after December
     15, 2002. See Note 7 for further disclosures.

     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.

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

     Fuel in SPP Area of Texas

     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 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 for under-recovered fuel costs.
     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 includes a
     recommendation 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 recommendations in the
     PFD. 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 two issues. 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. 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. TNC made a filing on July 15, 2003 addressing
     the remand issues. Intervenors and the PUCT Staff filed statements of
     position or testimony in August 2003 and TNC filed rebuttal testimony in
     September 2003. The intervenors recommended $14.3 million of
     disallowances for the two remanded issues. On September 9, 2003,
     portions of TNC's testimony which related to the requirements of the
     AEP/CSW merger settlement to share off-system sales margins were
     stricken by the ALJ. The ALJ ruled that the requirement to share
     off-system sales margins had been determined by the PUCT and that the
     scope of the remand was only to determine the off-system sales margin
     sharing methodology. 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
     thorough review of the evidence it is only reasonably possible that TNC
     will ultimately share margins after the end of the Texas fuel factor.
     Due to a provision established in the first quarter of 2003, the
     resolution of the fuel factor issue should have an immaterial impact on
     future results of operations, cash flows and financial condition.
     However, the ultimate decision could result in additional income
     reductions for these issues. It is presently expected that the ALJ's PFD
     and the PUCT's final decision regarding 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 to June 2000 and reflected
     the order in its financial statements. This final order was appealed to
     the Travis County District Court. In May 2003, the District Court upheld
     the PUCT's final order. That order is currently on appeal to the Third
     Court of Appeals.

     TCC Fuel Reconciliation

     In December 2002, TCC filed 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 TCC's 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. An ALJ report is expected in 2003 or the first quarter of
     2004.

     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. In July
     2003, the ALJ requested that additional information be provided in the
     TCC fuel reconciliation related to the impact of the TNC remand order on
     TCC. Management believes, based on advice of counsel, that it is only
     reasonably possible that it will ultimately be determined that TCC
     should share off-system sales margins after the end of the Texas fuel
     factor. However, an adverse ruling 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 5 "Customer Choice and Industry Restructuring."

     SWEPCo Texas 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. Any
     ruling by the PUCT preventing recovery of SWEPCo's fuel costs could have
     a material impact on future results of operations, cash flows and
     financial condition. Intervenor and PUCT Staff recommendations will be
     filed in November 2003 and hearings are scheduled for January 2004.

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

     Several parties including the Office of Public Utility Counsel (OPC) and
     cities served by both TCC and TNC appealed the PUCT's December 2001
     orders establishing initial PTB fuel factors for Mutual Energy CPL and
     Mutual Energy WTU. On June 25, 2003, the District Court ruled in both
     appeals. The Court ruled in the Mutual Energy WTU case that the PUCT
     lacked sufficient evidence to include unaccounted for energy in the fuel
     factor, and that the PUCT improperly shifted the burden of proof and the
     record lacked substantial evidence on the effect of loss of load due to
     retail competition on generation requirements. The Court upheld the
     initial PTB orders on all other issues. In the Mutual Energy CPL
     proceeding, the Court ruled that the PUCT improperly shifted the burden
     of proof and the record lacked substantial evidence on the effect of
     loss of load due to retail competition on generation requirements. The
     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 appealed the
     District Court decisions to the Third Court of Appeals 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 from the FERC of
     wholesale transmission rates determined in the UCOS proceeding. 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 including a nuclear
     decommissioning fund charge and a municipal franchise fee, a system
     benefit fund fee, a transition charge associated with securitization of
     regulatory assets and a credit for excess earnings. Certain rulings of
     the PUCT in the UCOS proceeding, including the initial determination of
     stranded costs, the requirement to refund TCC's excess earnings,
     regulatory treatment of nuclear insurance and distribution rates charged
     municipal customers, were appealed to the Travis County District Court
     by TCC and other parties to the proceeding. The District Court issued a
     decision on June 16, 2003, upholding the PUCT's UCOS order with one
     exception. The Court ruled that the refund of the 1999 through 2001
     excess earnings solely as a credit to non-bypassable transmission and
     distribution rates charged to REPs discriminates against residential and
     small commercial customers and is unlawful. The distribution rate credit
     began in January 2002. This decision could potentially affect the PTB
     rates charged by the AEP REP (Mutual Energy CPL) and could result in a
     refund to certain of its customers. Mutual Energy CPL was a subsidiary
     of AEP until December 23, 2002 when it was sold. Management estimates
     that the effect of 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 advice 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, Texas requested that TCC provide
     justification showing that its transmission and distribution rates
     should not be reduced. Other municipalities served by TCC passed similar
     rate review resolutions. In Texas, municipalities have original
     jurisdiction over rates of electric utilities within their municipal
     limits. Under Texas law, TCC 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 filed the requested support for its rates
     (test year ending June 30, 2003) with both the cities and the PUCT on
     November 3, 2003. TCC filed to decrease its wholesale transmission rates
     by $2 million or 2.5% and increase its retail energy delivery rates by
     $69 million or 19.2%. Management is unable to predict the ultimate
     effect of this proceeding on TCC's rates or its impact on TCC's results
     of operations, cash flows and financial condition.

     Louisiana Fuel Audit

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

     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, but it 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 6.

     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 OCC filed an application requiring
     PSO to file all documents necessary for a general rate review before
     August 1, 2003 (revised to October 31, 2003). In October 2003, PSO filed
     the required data for this case and requested an increase of $36 million
     annually, which is an 8.7% increase over existing base rates. A
     procedural schedule has not been set for this case. Management is unable
     to predict the ultimate effect of this review on PSO's rates or its
     impact on PSO's results of operations, cash flows and financial
     condition.

     PSO Fuel and Purchased Power

     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 in 2002 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. In August 2003, the OCC Staff filed
     testimony recommending recovery of $42.4 million ($44 million less two
     audit adjustments) over three years. In September 2003, the OCC expanded
     the case to include a full prudence review of PSO's 2001 fuel and
     purchased power practices. If the OCC does not permit recovery of the
     $42.4 million or determines, as a result of the review, that material
     fuel and purchased power cost should not be recovered, there will be an
     adverse effect on PSO's results of operations, cash flows and possibly
     financial condition.

     Virginia Fuel Factor Filing

     APCo filed with the Virginia SCC to reduce its fuel factor effective
     August 1, 2003. The requested fuel rate reduction would be effective for
     17 months and is estimated to reduce revenues by $36 million during that
     17-month period. By order dated July 23, 2003, the Virginia SCC approved
     APCo's requested fuel factor reduction on an interim basis, subject to
     further investigation. No other parties to the proceeding have raised
     any issues with respect to APCo's request and the Virginia SCC Staff has
     filed testimony recommending that APCo's request be approved. This fuel
     factor adjustment will reduce cash flows without impacting results of
     operations as any over-recovery or under-recovery of fuel costs would be
     deferred as a regulatory liability or a regulatory asset. A hearing on
     this matter was held on November 5, 2003.

     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 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. At a hearing held in April 2003, the utilities asked FERC
     to void the long-term contracts. In June 2003, the FERC issued an order
     affirming the ALJ's decision and denying the utilities' complaint. The
     utilities requested a rehearing. In August 2003, the FERC granted the
     request for rehearing. Management is unable to predict the outcome of
     this proceeding or its impact on future results of operations and cash
     flows.

     RTO Formation/Integration Costs

     With FERC approval, AEP East companies have been deferring costs
     incurred under FERC orders to form an RTO (the Alliance RTO) or join an
     existing RTO (PJM). In July 2003, the FERC issued an order approving our
     continued deferral of both our Alliance formation costs and our PJM
     integration costs including the deferral of a carrying charge. The AEP
     East companies have deferred approximately $24 million of RTO formation
     and integration costs and related carrying charges through September 30,
     2003. As a result of the subsequent delay in the integration of AEP's
     East transmission system into PJM, FERC declined to rule, in its July
     order, on our request to transfer the deferrals to regulatory assets,
     and to maintain the deferrals until such time as the costs can be
     recovered from all users of AEP's East transmission system. The AEP East
     companies will apply for permission to transfer the deferred
     formation/integration costs to a regulatory asset prior to integration
     with PJM. In August 2003, the Virginia SCC filed a request for rehearing
     of the July order, arguing that FERC's action was an infringement on
     state jurisdiction, and that FERC should not have treated Alliance RTO
     startup costs in the same manner as PJM integration costs. On October
     22, 2003, FERC denied the rehearing request.

     In 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 July 2003, the KPSC
     denied KPCo's request to join PJM based in part on a lack of evidence
     that it would benefit Kentucky retail customers. In August 2003, KPCo
     sought and was granted a rehearing allowing us to submit additional
     evidence. A hearing date has not been scheduled.

     In September 2003, the IURC issued an order approving I&M's transfer of
     functional control over its transmission facilities to PJM, subject to
     certain conditions included in the order. The IURC's order stated that
     AEP shall request and the IURC shall complete a review of Alliance
     formation costs ($2 million for I&M) before any deferral of the costs
     for future recovery. On September 30, 2003, AEP filed a petition for
     reconsideration of the IURC's order, asking the IURC to clarify that its
     discussion of the Alliance formation costs was not intended to cause an
     immediate write-off of the Indiana retail portion of these costs.

     In its July 2003 order, FERC indicated that it would review the deferred
     costs at the time they are transferred to a regulatory asset account and
     scheduled for amortization and recovery in the open access transmission
     tariff (OATT) to be charged by PJM. Management believes that the FERC
     will grant permission for the deferred RTO costs to be amortized and
     included in the OATT. Whether the amortized costs will be fully
     recoverable depends upon the state regulatory commissions' treatment of
     AEP East companies' portion of the OATT at the time they join PJM.
     Presently, retail rates are frozen or capped and cannot be increased for
     retail customers of CSPCo, I&M and OPCo. APCo's base rates are capped
     with no changes possible prior to January 1, 2004. We intend to file an
     application with FERC seeking permission to delay the amortization of
     the deferred RTO formation/integration costs until they are recoverable
     from all users of the transmission system including retail customers.
     Management is unable to predict the timing of when AEP will join PJM and
     if upon joining PJM whether FERC will grant a delay of recovery until
     the rate caps and freezes end. If AEP East companies do not obtain
     regulatory approval to join PJM, we are committed to reimburse PJM for
     certain project implementation costs (presently estimated at $23 million
     for the entire PJM integration project). Management intends to seek
     recovery of the deferred RTO formation/integration costs and project
     implementation cost reimbursements, if incurred. If the FERC ultimately
     decides not to approve a delay or the state commissions deny recovery,
     future results of operations and cash flows could be adversely affected.

     FERC Order on Regional Through and Out Rates

     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 (RTO Footprint). In
     October 2003, the FERC postponed the November 1, 2003 deadline to
     eliminate RTOR. 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 RTOR 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
     made a filing with the FERC supporting the justness and reasonableness
     of our rates in August 2003 and made a joint filing with unaffiliated
     utilities, on October 14, 2003, proposing a regional revenue replacement
     mechanism for the lost revenues, in the event that FERC eliminates AEP's
     ability to collect RTOR in the RTO Footprint. Also on October 14, 2003,
     FERC issued an order delaying the November 1, 2003 elimination of RTORs
     without setting a new date for such elimination. The AEP East companies
     received approximately $150 million of RTOR revenues from transactions
     delivering energy to customers in the RTO Footprint for the twelve
     months ended June 30, 2003. At this time, management is unable to
     predict the ultimate outcome of this investigation, or its impact on our
     future results of operations, cash flows and financial condition.

     Indiana Fuel Order

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

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

     Michigan 2004 Fuel Recovery Plan

     The MPSC's December 16, 1999 order approved a Settlement Agreement
     regarding the extended outage of the Cook Plant and fixed I&M Power
     Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers
     rate areas through December 2003. In accordance with the settlement,
     PSCR Plan cases were not required to be filed through the 2003 plan
     year. For the 2004 plan year, I&M was required to file a PSCR Plan case
     with the MPSC by September 30, 2003. I&M filed its 2004 PSCR Plan with
     the MPSC on September 30, 2003 seeking new fuel and power supply
     recovery factors to be effective in 2004.

5.   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   requiring the pricing of standard offer electric generation
           effective January 1, 2006 at the market price used by CSPCo and
           OPCo in their 1999 transition plan filings to estimate
           transition costs and

       o   imposing a $25,000 per company forfeiture for each day AEP
           fails to comply with its commitment to transfer control of
           transmission assets to an RTO

     Due to 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 currently unable to predict the
     timing of the AEP East companies' (including CSPCo and OPCo)
     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 Market Development Period (MDP) during
     which retail customers can choose their electric power suppliers or
     receive Default Service at frozen generation rates from the incumbent
     utility. The MDP began on January 1, 2001 and is scheduled to terminate
     no later than December 31, 2005. The PUCO may terminate the MDP for one
     or more customer classes before that date if it determines either that
     effective competition exists in the incumbent utility's certified
     territory or that there is a twenty percent switching rate of the
     incumbent utility's load by customer class. Following the MDP, retail
     customers will receive distribution and transmission service from the
     incumbent utility whose distribution rates will be approved by the PUCO
     and whose transmission rates will be approved by the FERC. Retail
     customers will continue to have the right to choose their electric
     power suppliers or receive Default Service, which must be offered by
     the incumbent utility at market rates. 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 MDP.

     As provided in stipulation agreements approved by the PUCO, we are
     deferring customer choice implementation costs that are in excess of
     $40 million. The agreements provide for the deferral of these costs as
     a regulatory asset until the next distribution base rate cases. At
     September 30, 2003, we have incurred $65 million and deferred $25
     million of such costs. Recovery of these regulatory assets will be
     subject to PUCO review in our next Ohio filings for new distribution
     rates. Approved rates will not become effective prior to 2009 for CSPCo
     and 2008 for OPCo. Management believes that the customer choice
     implementation costs were prudently incurred and the deferred amounts
     should be recoverable in future rates. If the PUCO determines that any
     of the deferred costs are unrecoverable, it would have an adverse
     impact on future results of operations and cash flows.

     Texas Restructuring

     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 and recovery of
     stranded plant costs as of December 31, 2001 including certain
     environmental costs incurred by May 1, 2003, final deferred fuel
     balance, net generation-related regulatory assets, unrefunded
     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 true-up issues.

     The Texas Legislation provides for an earnings test each year from 1999
     through 2001 and requires PUCT approval of the annual earnings test
     calculation. TCC, TNC and SWEPCo had appealed the PUCT's Final 2000
     Earnings Test Order to the Texas Court of Appeals. In August 2003, the
     Appeals Court reversed the PUCT order and the district court judgment
     affirming it and remanded the controversy back to the PUCT for
     proceedings consistent with the Appeals Court's decision. The PUCT
     requested rehearing of the Court of Appeal's decision. Our appeal of
     the same issue from the PUCT's 2001 Order is pending before the
     District Court. Since an expense and regulatory liability had been
     accrued in prior years in compliance with the PUCT Final Orders, the
     companies reversed a portion of their regulatory liability and credited
     amortization expense during the third quarter of 2003. Pre-tax amounts
     by company were $5.1 million for TCC, $2.6 million for TNC and $1.1
     million for SWEPCo.

     The Texas Legislation provides for the affiliated PTB REP to refund to
     its transmission and distribution (T&D) utility the excess of the PTB
     revenues over market prices (subject to certain conditions and a
     limitation of $150 per customer). This is the retail clawback. The
     retail clawback regulatory liability is to be included in the 2004
     true-up proceedings and netted against other true-up adjustments. If
     40% of the load for the residential or small commercial classes is
     served by competitive REPs, the retail clawback is not applicable for
     that class of customer. In July 2003, TCC and TNC filed to notify the
     PUCT that competitive REPs serve over 40% of the load in the small
     commercial class. On August 21, 2003, the PUCT dismissed these filings
     and ruled that TCC and TNC should refile no sooner than September 22,
     2003 in order to establish the required notice period. TCC and TNC
     refiled in late September 2003. In October 2003, the PUCT Staff
     recommended approval of TCC's application and denial of TNC's
     application. The PUCT Staff determined that only 39.9% of TNC's small
     commercial customers were served by competitive REPs as of the end of
     August 2003. If the PUCT denies TNC's application, TNC will likely meet
     the 40% threshold in September 2003 and refile its application. AEP had
     accrued a regulatory liability of approximately $9 million for the
     small commercial retail clawback on its REP's books. If the PUCT
     certifies that TCC and/or TNC have reached the 40% threshold, the
     regulatory liability would no longer be required for the small
     commercial class and could be reversed.

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

     In the fourth quarter of 2002, TCC decided to determine the market
     value of its generating assets through the sale of those assets for
     purposes of determining stranded costs for the 2004 true-up proceeding.
     In December 2002, TCC filed a plan of divestiture with the PUCT seeking
     approval of a sales process for all of its generating facilities. The
     amount of stranded costs under this market valuation methodology will
     be the amount by which the book value of TCC's generating assets,
     including regulatory assets and liabilities that were not securitized,
     exceeds the market value of the generation assets as measured by the
     net proceeds from the sale of the assets. It is anticipated that any
     such sale will result in significant stranded costs for purposes of
     TCC's 2004 true-up proceeding. 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 establish its market value
     for determining stranded plant 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 such 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 closing process for the plants sold is not
     expected to be completed before mid-2004, TCC requested that its 2004
     true-up proceeding be scheduled after completion of the divestiture of
     its generating assets.

     In March 2003, the PUCT dismissed TCC's divestiture filing, determining
     that it was more appropriate to address allowable valuation methods for
     the nuclear asset in a rulemaking proceeding. The PUCT approved a rule,
     in May 2003, which allows the market value obtained by selling nuclear
     assets to be used in determining stranded costs. The PUCT dismissed
     TCC's request to certify its proposed divestiture plan; therefore its
     divestiture plan will be subject to a review in the 2004 true-up
     proceeding. 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 or 60 days after the completion of the sale of
     TCC's generation assets, if later.

     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. Actual
     market power prices received in the state mandated auctions will
     replace the PUCT's earlier estimates of those market prices for 2002
     and 2003 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 cost instead of using the PUCT's ECOM model
     negative stranded cost estimate, 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 September 30, 2003, TCC recorded an additional $169
     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 negative ECOM estimate prohibited the
     recognition of the regulatory assets and revenues, as they cannot be
     recovered unless there are stranded costs. However, in March 2003, the
     Texas Court of Appeals ruled that under the restructuring legislation,
     other 2004 true-up items including the wholesale capacity auction
     true-up regulatory asset, could be recovered regardless of the level of
     stranded plant costs.

     In July 2003, the PUCT Staff published their proposed filing package
     for the 2004 true-up proceeding. Within the filing package are
     instructions and sample schedules that demonstrate the calculation of
     the wholesale capacity auction true-up. That calculation differs from
     the methodology being employed by TCC. TCC filed comments on the
     proposed 2004 true-up filing package in September 2003 and took
     exception to the methodology employed by the PUCT Staff. A true-up
     filing package will probably be approved by the PUCT in the fourth
     quarter of 2003. If the PUCT Staff's methodology is approved, TCC's
     wholesale capacity auction true-up regulatory asset could require
     adjustment.

     In October 2003, a coalition of consumer groups (the Coalition of
     Ratepayers) including the Office of Public Utility Counsel, the State
     of Texas, Cities served by CPL and Texas Industrial Energy Consumers
     filed a petition with the PUCT requesting that the PUCT initiate a
     rulemaking to amend the PUCT's stranded cost true-up rule (True-up
     Rule). The Coalition of Ratepayers proposed to amend the True-up Rule
     to revise the calculation of the wholesale capacity auction true-up. If
     adopted, the Coalition of Ratepayers' proposal would substantially
     reduce or possibly eliminate the wholesale capacity auction true-up
     regulatory asset that TCC has accrued in 2002 and 2003. The PUCT has
     requested that responses to the Coalition of Ratepayers' petition be
     filed by November 7, 2003. On November 5, 2003, the PUCT denied the
     Coalition of Ratepayers' petition.

     When the plant divestitures and the 2004 true-up proceeding are
     completed, TCC will file to recover PUCT-approved stranded costs and
     other true-up amounts that are in excess of current securitized amounts
     plus a carrying charge through a non-bypassable competition transition
     charge in rates of the regulated T&D utility. In addition, TCC may seek
     to securitize certain of the approved stranded plant costs and
     regulatory assets, not previously recovered through the non-bypassable
     transition charge. The annual costs of securitization are recovered
     through a non-bypassable rate surcharge collected by the T&D utility
     over the term of the securitization bonds.

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

     Arkansas Restructuring

     In February 2003, Arkansas repealed customer choice legislation
     originally enacted in 1999. Consequently, SWEPCo's Arkansas operations
     reapplied SFAS 71 regulatory accounting, which had been discontinued in
     1999. The reapplication of SFAS 71 had an insignificant effect on
     results of operations and financial condition. As a result of
     reapplying SFAS 71, derivative contract gains/losses for transactions
     within AEP's traditional marketing area allocated to Arkansas will not
     affect income until settled. That is, such positions will be recorded
     on the balance sheet as either a regulatory asset or liability until
     realized.

     West Virginia Restructuring

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

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

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

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

     Reapplying SFAS 71 in WV had an insignificant effect on results of
     operations and financial condition. As a result, derivative contract
     gains/losses related to transactions within AEP's traditional marketing
     area allocated to WV will not affect income until settled. That is,
     such positions will be recorded on the balance sheet as either a
     regulatory asset or liability until realized. Positions outside AEP's
     traditional marketing area will continue to be marked-to-market.

6.   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 $494 million and equity
     up to $31 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.

     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 (in general, the outstanding debt and
     equity associated with the Facility) or terminate the project and make a
     payment to Juniper for 89.9% of project costs (in general, the
     acquisition cost less certain financing costs.)

     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 also agreed to sell approximately
     800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) for a period
     of 20 years under a Power Purchase and Sale Agreement dated November 15,
     2002 (PPA) at a price which is currently in excess of market. Beginning
     May 1, 2003, AEP was obligated pursuant to the PPA to provide
     replacement capacity, energy and ancillary services to TEM. TEM has
     rejected as non-conforming the replacement capacity, energy and
     ancillary services tendered by AEP.

     On September 5, 2003, TEM and AEP separately filed declaratory judgment
     actions in the United State District Court for the Southern District of
     New York. Both suits seek a declaration from the Court of the parties'
     respective rights under the PPA. AEP alleges that TEM has breached the
     PPA. TEM alleges that the PPA is unenforceable or alternatively, that
     AEP has breached the PPA. If the PPA is terminated or found to be
     unenforceable, AEP could be adversely affected to the extent we are
     unable to find other purchasers of the power with similar contractual
     terms including comparable levels of profitability.

     AEP is the construction agent for Juniper. Construction is currently
     scheduled to be completed by the first quarter of 2004. If the Facility
     is not completed by April 30, 2004, TEM may claim that it can terminate
     the PPA 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 from Juniper for the acquisition cost at any time
     during the initial term if AEP has arranged a sale of the Facility to an
     unaffiliated third party. A purchase of the Facility from Juniper by AEP
     should not alter DOW's rights to lease the Facility or AEP's contract to
     purchase energy from DOW. If the lease were renewed for up to a 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, we may be
     required to make a payment (not to exceed $396 million) to Juniper of
     the excess of Juniper's acquisition costs over the proceeds from the
     sale, provided that AEP would not be required to make any payment if AEP
     has made the additional rental prepayment described below. AEP has
     guaranteed the performance of its subsidiaries to Juniper during the
     lease term. Due to FIN 45, at COD, AEP will be required to record the
     fair value (approximately $35 million) of this guarantee as a liability
     with an offsetting asset.

     As of September 30, 2003, Juniper's acquisition costs for the Facility
     totaled $460 million, and total costs for the completed Facility are
     currently expected to be approximately $525 million. For the 30-year
     extended lease term, the base lease rental is a variable rate obligation
     indexed to three-month LIBOR. Consequently as market interest rates
     increase, the base rental payments under this operating lease will also
     increase. Annual payments of approximately $18 million represent future
     minimum payments during the initial term calculated using the indexed
     LIBOR rate (1.14% at September 30, 2003). An additional rental
     prepayment (up to $396 million as of September 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 our financing
     transaction with Juniper is 89.9% of Juniper's project costs during the
     construction phase and up to $396 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 did 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 tubes were repaired and the
     unit returned to service in August 2003. Our share of the cost of repair
     for this outage was approximately $6 million. We had commitments to
     provide power to customers during the outage. Therefore, we were subject
     to fluctuations in the market prices of electricity and purchased
     replacement energy.

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

     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), AEPSC, APCo, CSPCo, I&M, and OPCo are involved in
     litigation regarding generating plant emissions under the Clean Air Act.
     The 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. The 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.

     On August 7, 2003, the District Court issued a decision following a
     liability trial in a case pending in the Southern District of Ohio
     against Ohio Edison Company, an unaffiliated utility. The District Court
     held that replacements of major boiler and turbine components that are
     infrequently performed at a single unit, that are performed with the
     assistance of outside contractors, that are accounted for as capital
     expenditures, and that require the unit to be taken out of service for a
     number of months are not "routine" maintenance, repair, and replacement.
     The District Court also held that a comparison of past actual emissions
     to projected future emissions must be performed prior to any non-routine
     physical change in order to evaluate whether an emissions increase will
     occur, and that increased hours of operation that are the result of
     eliminating forced outages due to the repairs must be included in that
     calculation. Based on these holdings, the District Court ruled that all
     of the challenged activities in that case were not routine, and that the
     changes resulted in significant net increases in emissions for certain
     pollutants. A remedy trial is scheduled for April 2004.

     Management believes that the Ohio Edison decision fails to properly
     evaluate and apply the applicable legal standards. The facts in our case
     also vary widely from plant to plant. Further, the Ohio Edison decision
     is limited to liability issues, and provides no insight as to the
     remedies that might ultimately be ordered by the Court.

     On August 26, 2003, the District Court for the Middle District of South
     Carolina issued a decision on cross-motions for summary judgment prior
     to a liability trial in a case pending against Duke Energy Corporation,
     an unaffiliated utility. The District Court denied all the pending
     motions, but set forth the legal standards that will be applied at the
     trial in that case. The District Court determined that the Federal EPA
     bears the burden of proof on the issue of whether a practice is "routine
     maintenance, repair, or replacement" and on whether or not a
     "significant net emissions increase" results from a physical change or
     change in the method of operation at a utility unit. However, the
     Federal EPA must consider whether a practice is "routine within the
     relevant source category" in determining if it is "routine." Further,
     the Federal EPA must calculate emissions by determining first whether a
     change in the maximum achievable hourly emission rate occurred as a
     result of the change, and then must calculate any change in annual
     emissions holding hours of operation constant before and after the
     change.

     On June 24, 2003, the United States Court of Appeals for the 11th
     Circuit issued an order invalidating the administrative compliance order
     issued by the Federal EPA to the Tennessee Valley Authority for similar
     alleged violations. The 11th Circuit determined that the administrative
     compliance order was not a final agency action, and that the enforcement
     provisions authorizing the issuance and enforcement of such orders under
     the Clean Air Act are unconstitutional.

     On June 26, 2003, the United States Court of Appeals for the District of
     Columbia Circuit granted a petition by the Utility Air Regulatory Group
     (UARG), of which our subsidiaries are members, to reopen petitions for
     review of the 1980 and 1992 Clean Air Act rulemakings that are the basis
     for the Federal EPA claims in our case and other related cases. On
     August 4, 2003, UARG filed a motion to separate and expedite review of
     their challenges to the 1980 and 1992 rulemakings from other unrelated
     claims in the consolidated appeal. The Circuit Court denied that motion
     on September 30, 2003. The central issue in these petitions concerns the
     lawfulness of the emissions increase test, as currently interpreted and
     applied by the Federal EPA in its utility enforcement actions. A
     decision by the D. C. Circuit Court could significantly impact further
     proceedings in our case.

     On August 27, 2003, the Administrator of the Federal EPA signed a final
     rule that defines "routine maintenance repair and replacement" to
     include "functionally equivalent equipment replacement." Under the new
     final rule, replacement of a component within an integrated industrial
     operation (defined as a "process unit") with a new component that is
     identical or functionally equivalent will be deemed to be a "routine
     replacement" if the replacement does not change any of the fundamental
     design parameters of the process unit, does not result in emissions in
     excess of any authorized limit, and does not cost more than twenty
     percent of the replacement cost of the process unit. The new rule is
     intended to have prospective effect, and will become effective in
     certain states 60 days after October 27, 2003, the date of its
     publication in the Federal Register, and in other states upon completion
     of state processes to incorporate the new rule into state law. On
     October 27, 2003 twelve states, the District of Columbia and several
     cities filed an action in the United States Court of Appeals for the
     District of Columbia Circuit seeking judicial review of the new rule.

     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 that
     the AEP System companies do not prevail, any capital and operating costs
     of additional pollution control equipment that may be required, as well
     as any penalties imposed, would adversely affect future results of
     operations, cash flows and possibly financial condition unless such
     costs can be recovered through regulated rates and market prices for
     electricity.

     In December 2000, Cinergy Corp., an unaffiliated utility, which operates
     certain plants jointly owned by CSPCo, reached a tentative agreement
     with the Federal EPA and other parties to settle litigation regarding
     generating plant emissions under the Clean Air Act. Negotiations are
     continuing between the parties in an attempt to reach final settlement
     terms. Cinergy's settlement could impact the operation of Zimmer Plant
     and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%,
     respectively, by CSPCo). Until a final settlement is reached, CSPCo will
     be unable to determine the settlement's impact on its jointly owned
     facilities and its future results of operations and cash flows.

     NOx Reductions

     The 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, the 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 the 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 the
     Federal EPA responds to the Court's remand. On April 30, 2002, the
     Federal EPA announced that May 31, 2004 is the compliance date for the
     Section 126 Rule. The 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 the 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 other combustion control technologies on
     a larger number of units. During 2001, 2002 and 2003, SCR technology
     commenced operations on units of Gavin, Amos, Mountaineer, Big Sandy and
     Cardinal plants. Construction of SCR technology at certain other AEP
     generating units continues. Other combustion control 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 $1 billion has been spent through
     September 30, 2003. Since compliance costs cannot be estimated with
     certainty, the actual cost to comply could be significantly different
     than these 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, these costs would adversely affect 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 from Enron remained unsettled
     at the date of Enron's bankruptcy. The timing of the resolution of the
     claims by the Bankruptcy Court is not certain.

     In connection with the 2001 acquisition of HPL, we acquired exclusive
     rights to use and operate the underground Bammel gas storage facility
     pursuant to an agreement with BAM Lease Company, a now-bankrupt
     subsidiary of Enron. This exclusive right to use the referenced facility
     is for a term of 30 years, with a renewal right for another 20 years and
     includes the use of the Bammel storage facility and the appurtenant
     pipelines. We have engaged in 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, Enron may
     attempt to reject certain of the agreements relating to the Bammel
     storage facility and certain appurtenant pipelines.

     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 gas, had entered into a financing arrangement in
     1997 with Enron and a group of banks. These banks purported to have
     certain rights to 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 65 billion cubic feet of 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 in the
     state court of Texas seeking a declaratory judgment that they have a
     valid and enforceable security interest in gas purportedly in the Bammel
     storage facility which would permit them to cause the withdrawal of 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, which was denied.  Trial is currently scheduled for December
     2003. Management is unable to predict the outcome of this lawsuit or
     its impact on our results of operations, cash flows and financial
     condition.

     On October 31, 2003, AEP Energy Services Gas Holding Company filed a
     lawsuit against Bank of America in the United States District Court for
     the Southern District of Texas. The lawsuit seeks damages for Bank of
     America's breach of contract and negligent misrepresentation in
     connection with transactions surrounding our acquisition of HPL from
     Enron. Bank of America led a lending syndicate involved in financing
     transactions that Enron and its subsidiaries undertook, including
     transactions that were prior to the sale of HPL and the leasing of the
     Bammel underground gas storage reservoir to HPL. The lawsuit asserts
     that we purchased HPL and undertook other related actions based on
     representations that Bank of America made about Enron's financial
     condition that Bank of America knew or should have known were false.

     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.

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

     Shareholder Lawsuits

     In the fourth quarter of 2002 and the first quarter of 2003, lawsuits
     alleging securities law violations and seeking class action
     certification were filed in federal District Court, Columbus, Ohio
     against AEP, certain AEP executives, and in some of the lawsuits,
     members of the AEP Board of Directors and certain investment banking
     firms. The lawsuits claim that we failed to disclose that alleged "round
     trip" trades resulted in an overstatement of revenues, that we failed to
     disclose that our traders falsely reported energy prices to trade
     publications that published gas price indices and that we failed to
     disclose that we did not have in place sufficient management controls to
     prevent "round trip" trades or false reporting of energy prices. The
     plaintiffs seek recovery of an unstated amount of compensatory damages,
     attorney fees and costs. The Court has appointed a lead plaintiff who
     has filed a Consolidated Amended Complaint. We have filed a Motion to
     Dismiss the Consolidated Amended Complaint. 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 the case
     to state court. We intend to continue to vigorously defend against these
     actions.

     In the fourth quarter of 2002, two shareholder derivative actions were
     filed in state court in Columbus, Ohio against AEP and its Board of
     Directors alleging a breach of fiduciary duty for failure to establish
     and maintain adequate internal controls over our gas trading operations.
     These cases have been stayed pending the outcome of our Motion to
     Dismiss the Consolidated Amended Complaint in the federal securities
     lawsuits. If these cases do proceed, we intend to vigorously defend
     against them. Also, in the fourth quarter of 2002 and the first quarter
     of 2003, three putative class action lawsuits were filed against AEP,
     certain executives and AEP's Employee Retirement Income Security Act
     (ERISA) Plan Administrator alleging violations of ERISA in the selection
     of AEP stock as an investment alternative and in the allocation of
     assets to AEP stock. The ERISA actions are pending in federal District
     Court, Columbus, Ohio. In these actions, the plaintiffs seek recovery of
     an unstated amount of compensatory damages, attorney fees and costs. We
     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.
     AEP has been dismissed from the case. The plaintiff had stated an
     intention to amend the complaint to add an AEP subsidiary as a
     defendant. The plaintiff amended the complaint but did not name any AEP
     company as a defendant.

     Cornerstone Lawsuit

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

     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. This case is in the initial pleading stage. We
     have filed a Motion to Dismiss. The Court has set a hearing on the
     Motion to Dismiss for January 2004. 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 in federal District Court in Columbus,
     Ohio against BOM claiming BOM had acted contrary to the appropriate
     trading contract and industry practice in calculating termination and
     liquidation amounts and that BOM had acknowledged just prior to the
     termination and liquidation that it owed us approximately $68 million.
     We are claiming that BOM owes us 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 resulted
     from Williams' repudiation of its obligations to provide physical power
     deliveries to AEP and Williams' failure to provide the monetary security
     required for natural gas deliveries by AEP. Consequently, both parties
     claimed default and terminated all outstanding natural gas and electric
     power trading deals among the various Williams and AEP affiliates.
     Williams claimed that we owed approximately $130 million in connection
     with the termination and liquidation of all trading deals. Williams and
     AEP settled the dispute and we paid $90 million to Williams in June
     2003. The settlement amount approximated the amount payable that, in the
     ordinary course of business, we recorded as part of our trading activity
     using MTM accounting. As a result, the resolution of this matter did not
     have a material impact on results of operations or financial condition.

     Arbitration of PG&E Energy Trading, LLC Claim

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

     Energy Market Investigation

     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 (CFTC), the U.S. Department of Justice and the
     California attorney general during 2002. Management responded to the
     inquiries and provided the requested information and has continued to
     respond to supplemental data requests in 2003.

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

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

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

     FERC Proposed Standard Market Design

     In July 2002, the FERC issued its Standard Market Design (SMD) notice of
     proposed rulemaking, which sought to standardize the structure and
     operation of wholesale electricity markets across the country. Key
     elements of FERC's proposal included standard rules and processes for
     all users of the electricity transmission grid, new transmission rules
     and policies, and the creation of certain markets to be operated by
     independent administrators of the grid in all regions. The FERC issued a
     white paper on the proposal in April 2003, in response to the numerous
     comments 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 2003. We have developed
     financial requirements for security implementation and compliance with
     these NERC standards, the costs of which are not expected to be material
     to our future results of operations and cash flows.

7.   GUARANTEES
     ----------

     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.

     LETTERS OF CREDIT

     AEP and certain of its 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 AEP or a subsidiary
     in the ordinary course of business. At September 30, 2003, the maximum
     future payments for all the LOCs are approximately $181 million with
     maturities ranging from September 30, 2003 to January 2011. Included in
     these amounts is TCC's LOC of approximately $40.9 million with a
     maturity date of November 2003. As the parent of all these subsidiaries,
     we hold all assets of the subsidiaries as collateral. There is no
     recourse to third parties in the event these letters of credit are
     drawn.

     GUARANTEES OF THIRD-PARTY OBLIGATIONS

     CSW Energy and CSW International

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

     AEP Utilities

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

     AEP

     AEP has guaranteed 50% of the principal and interest payments as well as
     50% of a Power Purchase Agreement (PPA) of Fort Lupton, an IPP of which
     AEP is a 50% owner. In the event Fort Lupton does not make the required
     debt payments, AEP has a maximum future payment exposure of
     approximately $6 million, which expires May 2008. In the event Fort
     Lupton is unable to perform under its PPA agreement, AEP has a maximum
     future payment exposure of approximately $14.8 million, which expires
     June 2019.

     AEP has guaranteed 50% of a security deposit for gas transmission as
     well as 50% of a Power Purchase Agreement (PPA) of Orange Cogeneration
     (Orange), an IPP of which AEP is a 50% owner. In the event Orange fails
     to make payments in accordance with agreements for gas transmission, AEP
     has a maximum future payment exposure of approximately $0.8 million,
     which expires June 2023. In the event Orange is unable to perform under
     its PPA agreement, AEP has a maximum future payment exposure of
     approximately $1.1 million, which expires June 2016.

     SWEPCo

     In connection with reducing the cost of the lignite mining contract for
     its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain
     conditions, to assume the obligations under 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 $60 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 September 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.

     On July 1, 2003, SWEPCo consolidated Sabine due to the application of
     FIN 46 (see Note 3). Upon consolidation, SWEPCo recorded the assets and
     liabilities of Sabine ($77.8 million). Also, after consolidation, SWEPCo
     currently records all expenses (depreciation, interest and other
     operation expense) of Sabine and eliminates Sabine's revenues against
     SWEPCo's fuel expenses. There is no cumulative effect of an accounting
     change recorded as a result of the requirement to consolidate, and there
     is no change in net income due to the consolidation of Sabine.

     Other

     See Power Generation Facility section of Note 6 "Commitments and
     Contingencies" for disclosure of related guarantees.

     INDEMNIFICATIONS AND OTHER GUARANTEES

     We entered into several types of contracts, which would require
     indemnifications. Typically these contracts include, but are not limited
     to, sale agreements, lease agreements, purchase agreements and financing
     agreements. Generally these agreements may include, but are not limited
     to, indemnifications around certain tax, contractual and environmental
     matters. With respect to sale agreements, our exposure generally does
     not exceed the sale price. We cannot estimate the maximum potential
     exposure for any of these indemnifications entered into prior to
     December 31, 2002 due to the uncertainty of future events. In the first
     nine months of 2003, we entered into several sale agreements discussed
     in Note 8. These sale agreements include indemnifications with a maximum
     exposure of approximately $67 million. There are no material liabilities
     recorded for any indemnifications entered into during the first nine
     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 September 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.

     See Note 10 "Leases" for disclosure of lease residual value guarantees.

8.   DISPOSITIONS, DISCONTINUED OPERATIONS, ASSETS HELD FOR SALE AND IMPAIRMENTS
     ---------------------------------------------------------------------------

     DISPOSITIONS

     Dispositions During the First Half of 2003

     During the first six months of 2003, we completed the sales of C3
     Communications, Mutual Energy Service Company, LLC, our Newgulf
     facility, our Nordic Trading business, our water heater rental program
     assets and our interest in AEP Gas Power Systems, LLC. The impact on our
     results of operations for the third quarter and for the nine months
     ended September 30, 2003 was not significant.

     Eastex

     We completed the sale of Eastex during the third quarter of 2003. We
     provided for a $218.7 million pre-tax asset impairment in the fourth
     quarter 2002, and the effect of the sale on third quarter 2003 results
     of operations was not significant. The results of operations of Eastex
     have been reclassified as Discontinued Operations in accordance with
     SFAS 144. The assets and liabilities of Eastex were reclassified on the
     Consolidated Balance Sheets from Assets Held for Sale and Liabilities
     Held for Sale to Discontinued Operations at December 31, 2002. The
     balance sheet components consisted of Current Assets of $15 million,
     Current Liabilities of $8 million and Other Liabilities of $4 million.

     DISCONTINUED OPERATIONS

     The results of operations of the entities shown below, affecting AEP,
     have been reclassified as Discontinued Operations for all periods
     presented. The assets and liabilities of Pushan Power Plant 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 September 30, 2003 and 2002:

<TABLE>
<CAPTION>

                                                                                  Pushan Power
                                          SEEBOARD            CitiPower              Plant               Eastex         Total
                                          --------            ---------           ------------           ------         -----
                                                                                 (in millions)
     <C>                                   <C>                  <C>                   <C>                  <C>            <C>
     2003 Revenue                          $-                   $-                    $14                  $12            $26
     2002 Revenue                           -                   (2)                    18                   22             38

     2003 Earnings
      (Loss) After Tax                     $-                   $-                     $-                   $-             $-
     2002 Earnings
      (Loss) After Tax                     46                   (8)                     4                   (3)            39

</TABLE>

<TABLE>
<CAPTION>

     For the nine months ended September 30, 2003 and 2002:

                                                                                  Pushan Power
                                          SEEBOARD            CitiPower              Plant               Eastex         Total
                                          --------            ---------           ------------           ------         -----
                                                                                 (in millions)
     <C>                                   <C>                 <C>                   <C>                 <C>            <C>
     2003 Revenue                           $-                   $-                  $41                  $58            $99
     2002 Revenue                          694                  204                   44                   50            992

     2003 Earnings
      (Loss) After Tax                      $-                   $-                  $(1)                $(15)          $(16)
     2002 Earnings
      (Loss) After Tax                      82                 (116)                   7                   (8)           (35)

</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.

     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 and
     governmental and regulatory delays. Results of operations of Pushan have
     been reclassified as Discontinued Operations in accordance with SFAS
     144. The assets and liabilities of Pushan have been reclassified on our
     Consolidated Balance Sheets as Assets Held for Sale and Liabilities 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 anticipate the
     sale of the turbine before the end of 2003. The Other Assets have been
     reclassified on our Consolidated Balance Sheets as Assets 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 reclassified on our Consolidated
     Balance Sheets as Assets 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 September
     30, 2003 and December 31, 2002 are as follows:

<TABLE>
<CAPTION>

                                      Pushan
                                      Power         Excess              Excess
                                      Plant       Real Estate          Equipment     Total
                                      ------      -----------          ---------     -----
     September 30, 2003                                    (in millions)
     ------------------
     <C>                              <C>            <C>                  <C>         <C>
     Assets:
     Current Assets                    $20             $-                  $-          $20
     Property, Plant and
      Equipment, Net                   144             18                   -          162
     Other Assets                        -              -                  12           12
                                      -----           ----                ----        -----
     Total Assets Held
      for Sale                        $164            $18                 $12         $194
                                      =====           ====                ====        =====

     Liabilities:
      Current Liabilities              $26             $-                  $-          $26
      Long-term Debt                    20              -                   -           20
      Other Liabilities                 52              -                   -           52
                                      -----           ----                ----        -----
     Total Liabilities
       Held for Sale                   $98             $-                  $-          $98
                                      =====           ====                ====        =====
</TABLE>

<TABLE>
<CAPTION>


                               Pushan                           Excess                 Water
                               Power    Newgulf     Nordic      Real       Excess      Heater      Tele-
                               Plant    Facility    Trading     Estate     Equipment   Program     communications    Total
                               ------   --------    -------     ------     ---------   -------     --------------    -----

     December 31, 2002                                                 (in millions)
     -----------------
     <C>                        <C>        <C>         <C>        <C>        <C>          <C>             <C>        <C>
     Assets:
      Current Assets             $19       $-          $35         $-         $-           $1             $-          $55
      Property, Plant and
       Equipment, Net            132        6            -         18          -           38              6          200
      Other Assets                 -        -           10          -         12            -              -           22
                                -----      ---         ----       ----       ----         ----            ---        -----
     Total Assets
       Held for Sale            $151       $6          $45        $18        $12          $39             $6         $277
                                =====      ===         ====       ====       ====         ====            ===        =====

     Liabilities:
      Current  Liabilities       $28       $-          $48         $-         $-           $-             $-          $76
      Long-term Debt              25        -            -          -          -            -              -           25
      Other Liabilities           26        -            3          -          -            -              -           29
                                -----      ---         ----       ----       ----         ----            ---        -----
     Total Liabilities
        Held for Sale            $79       $-          $51         $-         $-           $-             $-         $130
                                =====      ===         ====       ====       ====         ====            ===        =====

</TABLE>

     IMPAIRMENTS

     During the third quarter of 2003, we initiated an effort to sell four
     domestic Independent Power Producer (IPP) investments accounted for
     under the equity method. Based on studies of recent market conditions
     and assumptions, it was determined that an other than temporary
     impairment existed on two of the equity investments. The impairment was
     the result of the measurement of fair value that was triggered by our
     recent decision to sell the assets. A $70.0 million pre-tax ($45.5
     million net of tax) charge was recorded in September 2003 as a result of
     the other than temporary impairment of the equity interest under APB 18.
     This loss of investment value is included in Investment Value and Other
     Impairment Losses on our Consolidated Statements of Operations. These
     equity investments are included in our "Investments - Other" business
     segment.

9.   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 nine months ended
      September 30, 2003 and 2002 and the three months ended September 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
                                                ----------    ----------    ----------     -----       -----------  ------------
     Nine Months Ended September 30, 2003                                        (in millions)

     <C>                                         <C>             <C>            <C>         <C>          <C>           <C>
     Revenues from:
       External Customers                        $8,512          $2,791          $116        $439         $ -          $11,858
       Other Operating Segments                      15             255             -          74        (344)               -
     Discontinued Operations                          -               -             -         (16)          -              (16)
     Cumulative Effect of
      Accounting Changes,
      net of tax                                    237             (22)          (22)          -           -              193
     Net Income (Loss)                            1,123             (81)         (110)        (60)          -              872
     Total Assets                                29,262           3,062         1,847       1,714         194 (a)       36,079
     Gross Property Additions                       916              10             9           6           -              941
</TABLE>

<TABLE>
<CAPTION>

                                                                         Investments
                                                              ----------------------------------
                                                 Utility         Gas            UK                     Reconciling
                                                Operations    Operations    Operations     Other       Adjustments  Consolidated
                                                ----------    ----------    ----------     -----       -----------  ------------
     Nine Months Ended September 30, 2002                                        (in millions)
     <C>                                         <C>             <C>            <C>         <C>          <C>           <C>
     Revenues from:
       External Customers                        $7,858          $1,803          $187        $536         $ -          $10,384
       Other Operating Segments                       -             192             -         120        (312)               -
     Discontinued Operations                          -               -             -         (35)          -              (35)
     Cumulative Effect of
      Accounting Changes,
      net of tax                                      -               -             -        (350)          -             (350)
     Net Income (Loss)                              846             (75)            6        (459)          -              318
     Total Assets                                26,700           4,857         1,644       2,350         814(a)        36,365
     Gross Property Additions                       942              33            31         131           -            1,137

</TABLE>

<TABLE>
<CAPTION>


                                                                         Investments
                                                              ----------------------------------
                                                 Utility         Gas            UK                     Reconciling
                                                Operations    Operations    Operations     Other       Adjustments  Consolidated
                                                ----------    ----------    ----------     -----       -----------  ------------
     Three Months Ended September 30, 2003                                        (in millions)
     <C>                                         <C>             <C>            <C>         <C>          <C>           <C>
     Revenues from:
       External Customers                        $3,111            $860            $4        $134          $-           $4,109
       Other Operating Segments                      15             155             -          46        (216)               -
     Discontinued Operations                          -               -             -           -           -                -
     Cumulative Effect of
      Accounting Changes,
      net of tax                                      -               -             -           -           -                -
     Net Income (Loss)                              372             (20)          (51)        (44)          -              257
     Total Assets                                29,262           3,062         1,847       1,714         194(a)        36,079
     Gross Property Additions                       289               -             -           3           -              292

</TABLE>

<TABLE>
<CAPTION>
                                                                         Investments
                                                              ----------------------------------
                                                 Utility         Gas            UK                     Reconciling
                                                Operations    Operations    Operations     Other       Adjustments  Consolidated
                                                ----------    ----------    ----------     -----       -----------  ------------
     Three Months Ended September 30, 2002                                        (in millions)
     <C>                                         <C>             <C>            <C>         <C>          <C>           <C>
     Revenues from:
       External Customers                        $2,940            $700           $53        $118          $-           $3,811
       Other Operating Segments                       -              58             -          42        (100)               -
     Discontinued Operations                          -               -             -          39           -               39
     Cumulative Effect of
      Accounting Changes,
      net of tax                                      -               -             -           -           -                -
     Net Income (Loss)                              405               5            (5)         20           -              425
     Total Assets                                26,700           4,857         1,644       2,350         814(a)        36,365
     Gross Property Additions                       311              17            11          14           -              353

</TABLE>

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

10.  LEASES
     ------

     OPCo has entered into an agreement with JMG Funding LLP (JMG), an
     unrelated special purpose entity. JMG has a capital structure of which
     3% is equity from investors with no relationship to AEP or any of its
     subsidiaries and 97% is debt from commercial paper, pollution control
     bonds and other bonds. JMG was formed to design, construct and lease the
     Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber
     and leases it to OPCo. 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.

     On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46.
     Upon consolidation, OPCo recorded the assets and liabilities of JMG
     ($469.6 million). OPCo now records the depreciation, interest and other
     operating expenses of JMG and eliminates JMG's revenues against OPCo's
     operating lease expenses. There was no cumulative effect of an
     accounting change recorded as a result of our requirement to consolidate
     JMG, and there was no change in net income due to the consolidation of
     JMG.

     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.

     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 September 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.

11.  MINORITY INTEREST IN FINANCE SUBSIDIARY
     ---------------------------------------

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

     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 consolidated Caddis. Steelhead is an unconsolidated
     special purpose entity and had an original capital structure of $750
     million (currently approximately $525 million) of which 3% is equity
     from investors with no relationship to AEP or any of its subsidiaries
     and 97% is debt from a syndicate of banks. The $525 million invested in
     Caddis by Steelhead was loaned to SubOne. The loan to SubOne is due
     August 2006.

     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 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 September 30, 2003, SubOne has complied with the
     covenants contained in the credit agreement. In addition, the
     acceleration of AEP and certain subsidiaries' debt outstanding, in
     excess of $50 million, is an event of default under the credit
     agreement.

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

     SubOne has deposited $414 million in a cash reserve fund in order to
     comply with certain covenants in the credit agreement. Pursuant to the
     terms of the credit agreement, SubOne subsequently loaned these funds to
     affiliates, and AEP guaranteed the repayment obligations of these
     affiliates. These loans must be repaid in the event AEP's credit ratings
     fall below investment grade.

12.  FINANCING AND RELATED ACTIVITIES
     --------------------------------

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

<TABLE>
<CAPTION>
                                                                  Principal      Interest          Due
       Company                             Type of Debt             Amount         Rate            Date
       -------                             ------------           ---------      --------          ----
                                                                 (in millions)      (%)
     Issuances:

         <C>                           <C>                            <C>          <C>              <C>
         AEP                           Senior Unsecured Notes         $500           5.375          2010
         AEP                           Senior Unsecured Notes          300           5.25           2015
         AEP                           Other Debt                        2         Variable         2005
         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
         OPCo                          Senior Unsecured Notes          225           4.85           2014
         OPCo                          Senior Unsecured Notes          225           6.375          2033
         PSO                           Senior Unsecured Notes          150           4.85           2010
         SWEPCo                        Senior Unsecured Notes          100           5.375          2015
         SWEPCo                        Secured Note of Subsidiary       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>

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

         <C>                           <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                        9         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
         APCo                          Senior Unsecured Notes          125         Variable         2003
         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
         CSPCo                         First Mortgage Bonds             25           6.60           2003
         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
         PSO                           First Mortgage Bonds             65           7.25           2003
         SWEPCo                        First Mortgage Bonds             55           6.625          2003
         SWEPCo                        Secured Note of Subsidiary        2           4.47           2011
         SWEPCo                        Notes Payable                     1         Variable         2008
         TCC                           First Mortgage Bonds             18           7.50           2023
         TCC                           First Mortgage Bonds             16           6.875          2003
         TCC                           Securitization Bonds             51           3.54           2005

        Non-Registrant:
         AEP Subsidiary                Notes Payable                     7           6.225          2017
         AEP Subsidiary                Revolving Credit
                                        Agreement                      306         Variable         2003
         AEP Subsidiary                Senior Unsecured Notes           17           6.50           2003
         AEP Subsidiary                Other Debt                        6         Variable         2007

</TABLE>

<TABLE>
<CAPTION>


     In addition to the transactions reported in the table above, the
     following table lists intercompany issuances and retirements of debt due
     to AEP:

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

     Issuance:

         <C>                           <C>                            <C>           <C>             <C>
         Non-Registrant
          AEP Subsidiary               Notes Payable                  $225          5.57            2010

     Retirements:

         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 Subsidiary               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.

     AEP Credit extended its sale of receivables agreement from its May 28,
     2003 expiration to July 25, 2003, when the agreement was renewed for an
     additional 364 days. The new sale of receivables agreement, which
     expires on July 23, 2004, provides commitments of $600 million to
     purchase receivables from AEP Credit. At September 30, 2003, $529
     million of commitments to purchase accounts receivable were outstanding
     under the receivables agreement. All receivables sold represent
     affiliate receivables. AEP Credit maintains a retained interest in the
     receivables sold and this interest is pledged as collateral for the
     collection of receivables sold. The fair value of the retained interest
     is based on book value due to the short-term nature of the accounts
     receivable less an allowance for anticipated uncollectible accounts.

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

     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 a FERC approved rate of return on common equity (12.16% annually), a
return on other capital (net of temporary cash investments) and recovery of
costs including operation and maintenance, fuel and taxes.

Results of Operations

Net Income increased $74 thousand during the third quarter of 2003 compared with
the third quarter of 2002 and increased $27 thousand in the nine-month period
ended September 30, 2003 compared with the nine-month period ended September 30,
2002. 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.

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------
Operating Income

Operating Income increased $373 thousand for the third quarter primarily due to
the following:

     o     Operating Revenue increased as a result of increased recoverable
           expenses, primarily Other Operation and Maintenance, in accordance
           with the unit power agreements.

The increase in Operating Income was partially offset by the following:

     o     Fuel for Electric Generation expense increased primarily due to an
           increase in the average cost of coal.
     o     Other Operation and Maintenance increased in the current quarter due
           to a planned maintenance outage in September 2003.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Operating Income

Operating Income increased $467 thousand year-to-date primarily due to the
following:

     o     Operating Revenue increased as a result of increased recoverable
           expenses, primarily fuel, as net generation increased 15%
           year-to-date.
     o     Other Operation and Maintenance decreased year-to-date due to
           higher costs incurred for planned maintenance outages in the first
           quarter of 2002.
     o     The decrease in Taxes Other Than Income Taxes year-to-date
           reflects a decline in the accrual of Indiana's real and personal
           property taxes for the Rockport Plant, reflecting a favorable
           change in the tax law effective March 2002.

The increase in Operating Income was partially offset by the following:

     o     Fuel for Electric Generation expense increased primarily due to
           increased generation and an increase in the average cost of coal.
     o     Income Taxes attributable to operations increased due to an
           increase in pre-tax operating book income.

<PAGE>
<TABLE>
<CAPTION>


                                                           AEP GENERATING COMPANY
                                                            STATEMENTS OF INCOME
                                      For the Three and Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                  Three Months Ended                       Nine Months Ended
                                                                  ------------------                       -----------------
                                                                2003               2002                 2003                 2002
                                                                ----               ----                 ----                 ----
                                                                                         (in thousands)

<C>                                                           <C>                 <C>                 <C>                  <C>
OPERATING REVENUES                                            $59,008             $55,988             $179,004             $159,219
                                                              --------            --------            ---------            ---------


                     OPERATING EXPENSES
--------------------------------------------------------
Fuel for Electric Generation                                   27,514              26,702               87,148               65,737
Rent - Rockport Plant Unit 2                                   17,071              17,071               51,212               51,212
Other Operation                                                 2,691               2,023                7,683                9,259
Maintenance                                                     2,461               1,484                6,399                6,838
Depreciation                                                    5,695               5,643               16,981               16,918
Taxes Other Than Income Taxes                                   1,085               1,150                2,480                3,110
Income Taxes                                                      682                 479                1,927                1,438
                                                              --------            --------            ---------            ---------
TOTAL                                                          57,199              54,552              173,830              154,512
                                                              --------            --------            ---------            ---------

OPERATING INCOME                                                1,809               1,436                5,174                4,707

Nonoperating Income                                                 3                  74                   24                  108
Nonoperating Expenses (Credits)                                    44                  (8)                 286                   98
Nonoperating Income Tax Credits                                   878                 886                2,617                2,541
Interest Charges                                                  625                 457                1,944                1,700
                                                              --------            --------            ---------            ---------
NET INCOME                                                     $2,021              $1,947               $5,585               $5,558
                                                              ========            ========            =========            =========
</TABLE>

<TABLE>
<CAPTION>


                                                       STATEMENTS OF RETAINED EARNINGS
                                     For the Three and Nine Months Ended September 30, 2003 and 2002
                                                                 (Unaudited)

                                                                    Three Months Ended                       Nine Months Ended
                                                                    ------------------                       -----------------
                                                                2003                2002                 2003                 2002
                                                                ----                ----                 ----                 ----
                                                                                      (in thousands)

<C>                                                           <C>                 <C>                  <C>                  <C>
BALANCE AT BEGINNING OF PERIOD                                $19,384             $15,272              $18,163              $13,761

Net Income                                                      2,021               1,947                5,585                5,558

Cash Dividends Declared                                         1,172               1,050                3,515                3,150
                                                              --------            --------            ---------            ---------
BALANCE AT END OF PERIOD                                      $20,233             $16,169              $20,233              $16,169
                                                              ========            ========            =========            =========

</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
                                                                   ASSETS
                                                 September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                           2003                      2002
                                                                                           ----                      ----
                                                                                                   (in thousands)
                        ELECTRIC UTILITY PLANT
------------------------------------------------------------------------------
<C>                                                                                      <C>                       <C>
Production                                                                               $645,047                  $637,095
General                                                                                     4,278                     4,728
Construction Work in Progress                                                              12,928                    10,390
                                                                                         ---------                 ---------
TOTAL                                                                                     662,253                   652,213
Accumulated Depreciation                                                                  374,740                   358,174
                                                                                         ---------                 ---------
TOTAL - NET                                                                               287,513                   294,039
                                                                                         ---------                 ---------

Other Property and Investments                                                                119                       119

                           CURRENT ASSETS
------------------------------------------------------------------------------
Accounts Receivable - Affiliated Companies                                                 20,481                    18,454
Fuel                                                                                       14,829                    20,260
Materials and Supplies                                                                      5,179                     4,913
Prepayments                                                                                    24                        -
                                                                                         ---------                 ---------
TOTAL                                                                                      40,513                    43,627
                                                                                         ---------                 ---------

Regulatory Assets                                                                           5,674                     4,970
Deferred Charges                                                                            6,119                     6,974

TOTAL ASSETS                                                                             $339,938                  $349,729
                                                                                         =========                 =========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                           AEP GENERATING COMPANY
                                                               BALANCE SHEETS
                                                       CAPITALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                                  2003                2002
                                                                                                  ----                ----
                                                                                                        (in thousands)
                               CAPITALIZATION
------------------------------------------------------------------------------
<C>                                                                                               <C>                  <C>
Common Shareholder's Equity:
   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                                                                            20,233               18,163
                                                                                                ---------            ---------
Total Common Shareholder's Equity                                                                 44,667               42,597
Long-term Debt                                                                                    44,809               44,802
                                                                                                ---------            ---------
TOTAL                                                                                             89,476               87,399
                                                                                                ---------            ---------

Other Noncurrent Liabilities                                                                       1,305                  301

                             CURRENT LIABILITIES
------------------------------------------------------------------------------
Advances from Affiliates                                                                           6,879               28,034
Accounts Payable:
   General                                                                                             -                   26
   Affiliated Companies                                                                           14,176               15,907
Taxes Accrued                                                                                      4,360                2,327
Rent Accrued - Rockport Plant Unit 2                                                              23,427                4,963
Other                                                                                                603                1,111
                                                                                                ---------            ---------
TOTAL                                                                                             49,445               52,368
                                                                                                ---------            ---------

Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2                                      106,868              111,046

                           REGULATORY LIABILITIES
------------------------------------------------------------------------------
Deferred Investment Tax Credit                                                                    50,440               52,943
Amounts Due to Customers for Income Taxes                                                         15,191               16,670
                                                                                                ---------            ---------
TOTAL                                                                                             65,631               69,613
                                                                                                ---------            ---------

Deferred Income Taxes                                                                             27,213               29,002
Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                            $339,938             $349,729
                                                                                                =========            =========
</TABLE>

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



<PAGE>
<TABLE>
<CAPTION>


                                                           AEP GENERATING COMPANY
                                                          STATEMENTS OF CASH FLOWS
                                           For the Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                                                      2003               2002
                                                                                                      ----               ----
                                                                                                           (in thousands)
                          OPERATING ACTIVITIES
------------------------------------------------------------------------------
<C>                                                                                                  <C>                 <C>
Net Income                                                                                            $5,585              $5,558
Adjustments to Reconcile Net Income to Net Cash Flows From
 Operating Activities:
   Depreciation                                                                                       16,981              16,918
   Deferred Income Taxes                                                                              (3,268)             (3,328)
   Deferred Investment Tax Credits                                                                    (2,503)             (2,504)
   Amortization of Deferred Gain on Sale and Leaseback -
     Rockport Plant Unit 2                                                                            (4,178)             (4,178)
Changes in Certain Assets and Liabilities:
   Accounts Receivable                                                                                (2,027)            (11,370)
   Fuel, Materials and Supplies                                                                        5,165               1,741
   Accounts Payable                                                                                   (1,757)             31,076
   Taxes Accrued                                                                                       2,033               4,225
   Deferred Property Taxes                                                                              (795)               (881)
   Rent Accrued - Rockport Plant Unit 2                                                               18,464              18,464
Change in Other Assets                                                                                 1,383                 243
Change in Other Liabilities                                                                             (558)               (644)
                                                                                                     --------            --------
Net Cash Flows From Operating Activities                                                              34,525              55,320
                                                                                                     --------            --------
INVESTING ACTIVITIES - Construction Expenditures                                                      (9,855)             (6,956)
                                                                                                     --------            --------

                          FINANCING ACTIVITIES
------------------------------------------------------------------------------
Change in Advances from Affiliates                                                                   (21,155)            (46,197)
Dividends Paid                                                                                        (3,515)             (3,150)
                                                                                                     --------            --------
Net Cash Flows Used For Financing Activities                                                         (24,670)            (49,347)
                                                                                                     --------            --------

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 $2,200,000 and $1,983,000
and for income taxes was $5,939,000 and $2,442,000 in 2003 and 2002,
respectively.

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



<PAGE>
                    AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                 ----------------------------------------------


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

Net Income decreased $27 million for the third quarter, but increased $43
million year-to-date. The decreased income for the quarter is due to decreased
margins on system sales, offset in part by the recognition of non-cash earnings
related to legislatively mandated capacity auctions and regulatory assets
established in Texas of $39 million net of tax. The increased income for the
year-to-date is associated with the recognition of non-cash earnings related to
the capacity auction true-up in Texas of $110 million net of tax, offset in part
by decreased margins on system sales.

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

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Operating Income

Operating Income decreased $34 million primarily due to:

     o   Decreased  system sales,  including those to REPs, of $75 million,
         due mainly to decreased KWH sales and a decrease in the overall
         average price per KWH.
     o   Decreased revenues from ERCOT for various services, including balancing
         energy, of $45 million.
     o   The 2002 ICR adjustments that accounted for approximately $60
         million of the decrease (See "ICR Explanation: in Note 6 in the
         Annual Report, as updated by the Current Report on Form 8-K dated
         May 14, 2003, for discussion of the ICR adjustments).
     o   Decreased delivery revenues of $25 million partially due to a 7%
         decrease in cooling degree days.
     o   Decreased transmission revenues of $6 million.
     o   Increased  fuel and  purchased  electricity  on a combined  basis of
         $10 million.  Fuel  increased  almost  entirely due to increased per
         unit fuel costs, which rose 54%, mostly due to natural gas prices.
         Purchased power decreased in large part due to the 2002 ICR
         adjustments of $51 million (see "ICR Explanation" in Note 6 in the
         Annual Report, as updated by the Current Report on Form 8-K dated
         May 14, 2003, for discussion of the ICR adjustments.) While purchased
         KWH increased 38%, the average cost per unit decreased 16%.
     o   Increased Other Operation expense of $3 million due mainly to
         accretion  expense  associated with the adoption of SFAS 143
         (see Note 2).
     o   Increased maintenance expense of $1 million due mainly to unscheduled
         repairs at the STP nuclear plant.

The decrease in Operating Income was partially offset by:

     o   Reliability Must Run (RMR) revenues from ERCOT of $66 million
         which include both fuel recovery and a fixed cost component of $9
         million (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   Revenues associated  with  establishing  regulatory  assets in Texas
         of $61 million for the third quarter 2003 (see "Texas Restructuring"
         in Note 4).
     o   Increased revenues from risk management activities of $20 million.
     o   Decreased Depreciation and Amortization expense of $16 million due
         mainly to the reversal of prior years' excess earnings accruals
         under the Texas restructuring legislation due to a favorable
         Appeals Court ruling (See Note 4), 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   Decreased Income Taxes of $26 million due mainly to decreases in
         pre-tax operating book income.

Other Impacts on Earnings

Nonoperating Income increased $15 million primarily due to increased gains from
risk management activities partially offset by lower non-utility revenues
associated with energy related construction projects for third parties.

Nonoperating Expense decreased $7 million primarily due to lower non-utility
expenses associated with energy related construction projects for third parties.

Nonoperating Income Tax Expense (Credit) increased $8 million due to higher
pre-tax nonoperating book income.

Interest Charges increased $7 million primarily due to increased average levels
of debt outstanding during the quarter.


Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Operating Income

Operating Income increased $35 million primarily due to:

     o   Revenues  associated with  establishing  regulatory  assets in Texas
         of $169 million in 2003 (see "Texas  Restructuring" in Note 4).
     o   Reliability Must Run (RMR) revenues from ERCOT of $188 million
         which include both fuel recovery and a fixed cost component of $26
         million (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 revenues of $33 million resulting from risk management
         activities.
     o   Decreased Depreciation and Amortization expense of $23 million 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 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   Decreased  system sales,  including  those to REPs, of $34 million due
         mainly to both lower KWH sales and a decrease in the overall average
         price per KWH.
     o   Revenues from ERCOT for various services, including balancing energy,
         which declined $39 million.
     o   The 2002 ICR adjustments that accounted for approximately $60
         million of the decrease (See "ICR Explanation" in Note 6 in the
         Annual Report, as updated by the Current Report on Form 8-K dated
         May 14, 2003, for discussion of the ICR adjustments).
     o   Decreased  delivery  revenues  of $41 million  driven by a 10%
         decrease  in cooling  degree days and a slight  decrease in heating
         degree days.
     o   Increased  provisions  for rate  refunds of $39 million due mainly to
         Texas fuel issues (see "TCC Fuel  Reconciliation"  in Note 3).
     o   Net increases in fuel and purchased electricity on a combined
         basis of $175 million to replace portions of the energy from the
         non-RMR mothballed plants and the unscheduled forced outage at the
         STP nuclear unit (See "Significant Factors" below). KWH purchased
         increased 108% while the total cost increased 90%. Although the
         KWH generated decreased, fuel costs increased due to 43% higher
         per unit costs attributable mostly to natural gas. This increase
         was partially offset by the effect of the 2002 ICR adjustments.
     o   Increased Maintenance expense of $14 million due mainly to the STP
         Unit 2 forced outage in the first quarter and the STP Unit 1
         scheduled refueling outage and forced outage in the second and
         third quarters of 2003.
     o   Increased Income Taxes of $14 million due mainly to increases in
         pre-tax operating book income.

Other Impacts on Earnings

Nonoperating Income increased $19 million primarily due to increased gains from
risk management activities partially offset by lower non-utility revenues
associated with energy related construction projects for third parties.

Nonoperating Expense decreased $9 million primarily due to lower non-utility
expenses associated with energy related construction projects for third parties.

Nonoperating Income Tax Expense (Credit) increased $9 million due to higher
pre-tax nonoperating book income.

Interest Charges increased $11 million primarily due to the replacement of lower
cost short-term floating rate debt with longer-term higher cost fixed rate debt.

Cumulative Effect of Accounting Change

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

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

Credit Ratings

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

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

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of TCC's rating for unsecured debt from Baa1 to Baa2 and secured debt from A3 to
Baa1. The completion of this review was a culmination of ratings action started
during 2002. With the completion of the reviews, Moody's has placed AEP and its
rated subsidiaries on stable outlook. In March 2003, S&P lowered AEP and our
senior unsecured debt and first mortgage bonds ratings from BBB+ to BBB.

Cash Flow

Cash flows for the nine months ended September 30, 2003 and 2002 were as
follows:

<TABLE>
<CAPTION>

                                                               2003             2002
                                                               ----             ----
                                                                   (in thousands)
   <C>                                                       <C>              <C>
   Cash and cash equivalents at beginning of period           $85,420         $10,909
   Cash flow from (used for):
     Operating activities                                     231,397          33,502
     Investing activities                                     (94,818)        (97,952)
     Financing activities                                    (179,247)        110,179
                                                             ---------        --------
   Net increase (decrease) in cash and cash equivalents       (42,668)         45,729
                                                             ---------        --------
   Cash and cash equivalents at end of period                 $42,752         $56,638
                                                             =========        ========
</TABLE>

Operating Activities

Cash flow from operating activities increased $198 million from the prior year
primarily due to a $43 million increase in net income as explained above and
accounts receivables changes related to reduced energy sales due primarily to
REP related sales receivables, partially offset by the non-cash Texas wholesale
capacity auction revenues recorded in 2003.

Investing Activities

Construction expenditures in 2003 versus 2002 decreased by $3 million.
Construction expenditures of $95 million in the current year were focused on
improved service reliability projects for transmission and distribution systems
costing $68 million.

Financing Activities

We obtained the additional funds needed for investing and financing activities
through new borrowings of $800 million in 2003 and $997 million in 2002. Current
year debt proceeds replaced short and long-term debt. Prior year debt proceeds
replaced long-term debt and retired common stock.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2003
were:


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

       Senior Unsecured Notes        $150              3.00              2005
       Senior Unsecured Notes         100            Variable            2005
       Senior Unsecured Notes         275              5.50              2013
       Senior Unsecured Notes         275              6.65              2033



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

        First Mortgage Bonds          $16               6.875             2003
        First Mortgage Bonds           18               7.50              2023
        Securitization Bonds           51               3.54              2005



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

Possible Divestitures

In June 2003, we began actively seeking buyers for 4,497 megawatts of
unregulated generation capacity in Texas. The value received from this
disposition will be used to calculate our strande cost in Texas (see Note 4).
We expect to receive final bids in the fourth quarter of 2003.

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 tubes were repaired and the unit
returned to service in August 2003. Our share of the cost of repair for this
outage was approximately $6 million. We had commitments to provide power to
customers during the outage. Therefore, we were subject to fluctuations in the
market prices of electricity and purchased replacement energy.

Industry 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 began in the ERCOT
area of Texas. 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.

Restructuring legislation in Texas provides that the PUCT address several issues
in the 2004 true-up proceeding. One of these issues is the wholesale capacity
auction true-up. We have recorded $431 million of regulatory assets and related
revenues through September 30, 2003 based upon our estimate.

In July 2003, the PUCT Staff published their proposed filing package for the
2004 true-up proceeding. Within the filing package are instructions and sample
schedules that demonstrate the calculation of the wholesale capacity auction
true-up. That calculation differs from our methodology. We filed comments on the
proposed 2004 true-up filing package in September 2003 and took exception to the
methodology employed by the PUCT Staff. A true-up filing package will probably
be approved by the PUCT in the fourth quarter of 2003. If the PUCT Staff's
methodology is approved, our wholesale capacity auction true-up regulatory asset
could require adjustment.

In October 2003, a coalition of consumer groups (the Coalition of Ratepayers)
including the Office of Public Utility Counsel, the State of Texas, Cities
served by CPL and Texas Industrial Energy Consumers filed a petition with the
PUCT requesting that the PUCT initiate a rulemaking to amend the PUCT's stranded
cost true-up rule (True-up Rule). The Coalition of Ratepayers proposed to amend
the True-up Rule to revise the calculation of the wholesale capacity auction
true-up. If adopted, the Coalition of Ratepayers' proposal would substantially
reduce or possibly eliminate the wholesale capacity auction true-up regulatory
asset that we have accrued in 2002 and 2003. The PUCT requested that responses
to the Coalition of Ratepayers' petition be filed by November 7, 2003. On
November 5, 2003, the PUCT denied the Coalition of Ratepayers' petition.

See Notes 3 and 4 for further discussion.

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, wholesale capacity auction true-up regulatory assets,
other restructuring true-up items and costs, it could have a material adverse
effect on results of operations, cash flows and possibly financial condition.

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.

Roll-Forward of MTM Risk Management Contract Net Assets

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

<TABLE>
<CAPTION>



                     Roll-Forward of MTM Risk Management Contract Net Assets
                             Nine Months Ended September 30, 2003
                                     (in thousands)

        Domestic Power
        --------------

        <C>                                                                     <C>
        Beginning Balance December 31, 2002                                      $5,414
        (Gain) Loss from Contracts  Realized/Settled
         During  the Period (a)                                                  (2,671)
        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)                                                           16,097
        Changes in Fair Value of Risk Management Contracts
        Allocated to Regulated Jurisdictions (e)                                      -
                                                                                --------
        Total MTM Risk Management Contract Net Assets                            19,027
        Net Non-Trading Related Derivative Contracts                                464
                                                                                --------
        Net Fair Value of Risk Management and Derivative
         Contracts September 30, 2003                                           $19,491
                                                                                ========

</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,
             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 September 30, 2003

                                                      Remainder                                                  After
                                                        2003        2004        2005        2006       2007      2007        Total
                                                      ---------     ----        ----        ----       ----      -----       -----
                                                                                      (in thousands)
     <C>                                              <C>          <C>         <C>         <C>        <C>       <C>        <C>
     Prices Provided by Other External  Sources
     - OTC Broker Quotes (a)                            $410       $4,572      $2,020      $1,771       $419        $-      $9,192
     Prices Based on Models and Other  Valuation
     Methods (b)                                         688        1,662       1,054       1,275      1,406     3,750       9,835
                                                      -------      -------     -------     -------    -------   -------    --------

     Total                                            $1,098       $6,234      $3,074      $3,046     $1,825    $3,750     $19,027
                                                      =======      =======     =======     =======    =======   =======    ========

</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). In accordance with GAAP, all amounts are presented net of
related income taxes.

                 Total Other Comprehensive Income (Loss) Activity
                       Nine Months Ended September 30, 2003

                                                       Domestic
                                                        Power
                                                       --------
                                                   (in thousands)
     Accumulated OCI, December 31, 2002                  $(36)
     Changes in Fair Value (a)                            200
     Reclassifications from OCI to Net
      Income (b)                                          137
                                                         -----
     Accumulated OCI Derivative Gain September
      30, 2003                                           $301
                                                         =====

(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 $525 thousand gain.

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:

                 September 30, 2003                     December 31, 2002
                 ------------------                     -----------------
                  (in thousands)                         (in thousands)
              End  High  Average  Low                End   High  Average  Low
              ---  ----  -------  ---                ---   ----  -------  ---
             $278  $788   $363    $78               $115   $353    $126   $26



<PAGE>
<TABLE>
<CAPTION>


                                               AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                  CONSOLIDATED STATEMENTS OF INCOME
                                   For the Three and Nine Months Ended September 30, 2003 and 2002
                                                              (Unaudited)

                                                                      Three Months Ended                  Nine Months Ended
                                                                      ------------------                  -----------------
                                                                    2003              2002             2003                2002
                                                                    ----              ----             ----                ----
                                                                                                           (in thousands)
              OPERATING REVENUES
-------------------------------------------------------------
<C>                                                               <C>                <C>            <C>                  <C>
Electric Generation, Transmission and Distribution                $443,578           $111,051       $1,264,757            $306,238
Sales to AEP Affiliates                                             41,551            435,209          131,176             879,323
                                                                  ---------          ---------      -----------          ----------
TOTAL                                                              485,129            546,260        1,395,933           1,185,561
                                                                  ---------          ---------      -----------          ----------

               OPERATING EXPENSES
-------------------------------------------------------------
Fuel for Electric Generation                                        24,475             21,081           73,244              70,808
Fuel from Affiliates for Electric  Generation                       72,776             42,576          155,976             137,133
Purchased Electricity for Resale                                   116,562            151,012          305,338             160,996
Purchased Electricity from AEP Affiliates                              273            (10,433)          19,045              10,058
Other Operation                                                     74,192             71,023          213,884             208,984
Maintenance                                                         16,657             15,239           54,567              40,980
Depreciation and Amortization                                       46,151             62,242          142,084             165,012
Taxes Other Than Income Taxes                                       24,747             24,774           67,509              76,170
Income Taxes                                                        24,794             50,542           91,171              77,452
                                                                  ---------          ---------      -----------          ----------
TOTAL                                                              400,627            428,056        1,122,818             947,593
                                                                  ---------          ---------      -----------          ----------

OPERATING INCOME                                                    84,502            118,204          273,115             237,968

Nonoperating Income                                                 25,006             10,234           43,069              24,237
Nonoperating Expenses                                                3,647             10,184           14,479              23,049
Nonoperating Income Tax Expense (Credit)                             6,319             (1,522)           7,117              (2,037)
Interest Charges                                                    33,321             26,393          100,343              89,830
                                                                  ---------          ---------      -----------          ----------
Income Before Cumulative Effect of Accounting Change                66,221             93,383          194,245             151,363
Cumulative Effect of Accounting Change (Net of Tax)                      -                  -              122                   -
                                                                  ---------          ---------      -----------          ----------
NET INCOME                                                          66,221             93,383          194,367             151,363

Gain on Reacquired Preferred Stock                                       -                  4                -                   4
Preferred Stock Dividend Requirements                                   60                 60              181                 181
                                                                  ---------          ---------      -----------          ----------

EARNINGS APPLICABLE TO COMMON  STOCK                               $66,161           $ 93,327         $194,186            $151,186
                                                                  =========          =========      ===========          ==========
</TABLE>

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

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


<PAGE>
<TABLE>
<CAPTION>



                                                   AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                         CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
                                                             COMPREHENSIVE INCOME
                                                                (in thousands)
                                                                 (Unaudited)


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

<C>                                                       <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                                                                  (115,505)                         (115,505)
Preferred Stock Dividends                                                                   (181)                             (181)
Capital Stock Gains                                                                            4                                 4
                                                                                                                        -----------
TOTAL                                                                                                                      898,413
                                                                                                                        -----------

          COMPREHENSIVE INCOME
-------------------------------------------------------------
Other Comprehensive Income,
 Net of  Taxes:
    Unrealized Gain on Cash Flow Hedges                                                                        $58              58
NET INCOME                                                                               151,363                           151,363
TOTAL COMPREHENSIVE INCOME                                                                                                 151,421
                                                          ---------     ---------     -----------         ---------     -----------
SEPTEMBER 30, 2002                                         $55,292      $132,606        $861,878               $58      $1,049,834
                                                          =========     =========     ===========         =========     ===========


JANUARY 1, 2003                                            $55,292      $132,606        $986,396          $(73,160)     $1,101,134

Common Stock Dividends                                                                   (90,601)                          (90,601)
Preferred Stock Dividends                                                                   (181)                             (181)
                                                                                                                        -----------
TOTAL                                                                                                                    1,010,352

          COMPREHENSIVE INCOME
-------------------------------------------------------------
Other Comprehensive Income,
  Net of Taxes:
    Unrealized Gain on Cash Flow Hedges                                                                        337             337
NET INCOME                                                                               194,367                           194,367
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                 194,704
                                                          ---------     ---------     -----------         ---------     -----------
SEPTEMBER 30, 2003                                         $55,292      $132,606      $1,089,981          $(72,823)     $1,205,056
                                                          =========     =========     ===========         =========     ===========

</TABLE>

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


<PAGE>
<TABLE>
<CAPTION>



                                                   AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                        CONSOLIDATED BALANCE SHEETS
                                                                   ASSETS
                                                   September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                                    2003                  2002
                                                                                                    ----                  ----
                                                                                                          (in thousands)


                     ELECTRIC UTILITY PLANT
-------------------------------------------------------------
<C>                                                                                              <C>                    <C>
Production                                                                                       $3,001,939             $2,903,942
Transmission                                                                                        776,256                698,964
Distribution                                                                                      1,365,327              1,296,731
General                                                                                             263,567                258,386
Construction Work in Progress                                                                        59,385                200,947
Nuclear Fuel                                                                                         34,042                 34,942
                                                                                                 -----------            -----------
TOTAL                                                                                             5,500,516              5,393,912
Accumulated Depreciation and Amortization                                                         2,151,475              2,173,668
                                                                                                 -----------            -----------
TOTAL - NET                                                                                       3,349,041              3,220,244
                                                                                                 -----------            -----------

Other Property and Investments                                                                        8,598                  3,977
Securitized Transition Assets                                                                       703,293                734,591
Long-term Risk Management Assets                                                                     16,823                  4,392

                        CURRENT ASSETS
-------------------------------------------------------------
Cash and Cash Equivalents                                                                            42,752                 85,420
Advances to Affiliates                                                                               26,327                     -
Accounts Receivable:
   General                                                                                          169,304                113,543
   Affiliated Companies                                                                             110,360                121,324
   Allowance for Uncollectible Accounts                                                                (248)                  (346)
Fuel Inventory                                                                                       18,400                 32,563
Materials and Supplies                                                                               48,696                 51,593
Accrued Utility Revenues                                                                             34,757                 27,150
Risk Management Assets                                                                               14,007                 22,493
Prepayments and Other Current Assets                                                                  4,682                  2,133
                                                                                                 -----------            -----------
TOTAL                                                                                               469,037                455,873
                                                                                                 -----------            -----------

Regulatory Assets                                                                                   659,427                458,552
Regulatory Assets Designated for or Subject to Securitization                                       320,713                336,444
Nuclear Decommissioning Trust Fund                                                                  114,930                 98,474
Deferred Charges                                                                                     66,962                 43,891

TOTAL ASSETS                                                                                     $5,708,824             $5,356,438
                                                                                                 ===========            ===========
</TABLE>

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



<PAGE>
<TABLE>
<CAPTION>


                                                  AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                        CONSOLIDATED BALANCE SHEETS
                                                       CAPITALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)





                                                                                                      2003                2002
                                                                                                      ----                ----
                                                                                                            (in thousands)

                        CAPITALIZATION
-------------------------------------------------------------
<C>                                                                                               <C>                 <C>
Common Shareholder's Equity:
  Common Stock - $25 Par Value:
    Authorized - 12,000,000 Shares
    Outstanding - 2,211,678 Shares                                                                   $55,292             $55,292
    Paid-in Capital                                                                                  132,606             132,606
    Accumulated Other Comprehensive Income (Loss)                                                    (72,823)            (73,160)
    Retained Earnings                                                                              1,089,981             986,396
                                                                                                  -----------         -----------
Total Common Shareholder's Equity                                                                  1,205,056           1,101,134
  Cumulative Preferred Stock Not Subject to Mandatory Redemption                                       5,940               5,942
  CPL - Obligated Mandatorily Redeemable Preferred Securities of
   Subsidiary Trust Holding Solely Junior Subordinated Debentures of TCC                                   -             136,250
Long-term Debt                                                                                     2,081,274           1,209,434
                                                                                                  -----------         -----------
TOTAL                                                                                              3,292,270           2,452,760
                                                                                                  -----------         -----------

Other Noncurrent Liabilities                                                                         326,943              74,572

                       CURRENT LIABILITIES
-------------------------------------------------------------
Short-term Debt - Affiliates                                                                               -             650,000
Long-term Debt Due Within One Year                                                                   210,251             229,131
Advances from Affiliates                                                                                   -             126,711
Accounts Payable:
 General                                                                                              88,601              72,199
 Affiliated Companies                                                                                 91,655              36,242
Customer Deposits                                                                                      1,411                 666
Taxes Accrued                                                                                         48,834              24,791
Interest Accrued                                                                                      24,467              51,205
Risk Management Liabilities                                                                            6,030              19,811
Other                                                                                                 27,075              36,698
                                                                                                  -----------         -----------
TOTAL                                                                                                498,324           1,247,454
                                                                                                  -----------         -----------

Deferred Income Taxes                                                                              1,281,787           1,261,252
Deferred Investment Tax Credits                                                                      113,781             117,686
Long-term Risk Management Liabilities                                                                  5,309               1,713
Regulatory Liabilities and Deferred Credits                                                          190,410             201,001
Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                              $5,708,824          $5,356,438
                                                                                                  ===========         ===========
See Notes to Respective Financial Statements beginning on page L-1.
</TABLE>




<PAGE>
<TABLE>
<CAPTION>


                                                  AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                           For the Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                                                 2003                 2002
                                                                                                 ----                 ----
                                                                                                       (in thousands)
                   OPERATING ACTIVITIES
-------------------------------------------------------------
<C>                                                                                            <C>                   <C>
Net Income                                                                                     $194,367              $151,363
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Depreciation and Amortization                                                                142,084               165,012
   Deferred Income Taxes                                                                         36,386               (14,620)
   Deferred Investment Tax Credits                                                               (3,905)               (3,905)
   Cumulative Effect of Accounting Change                                                          (122)                   -
   Mark-to-Market of Risk Management Contracts                                                  (13,426)               (4,613)
   Texas Wholesale Clawback                                                                    (169,000)                   -
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                                     (44,895)             (258,663)
   Fuel, Materials and Supplies                                                                  17,060                (6,214)
   Interest Accrued                                                                             (26,738)               17,375
   Accrued Utility Revenues                                                                      (7,607)                   -
   Accounts Payable                                                                              71,815               (16,306)
   Taxes Accrued                                                                                 24,043                61,198
   Deferred Property Tax                                                                        (10,050)               (9,560)
Change in Other Assets                                                                           14,359               (61,836)
Change in Other Liabilities                                                                       7,026                14,271
                                                                                               ---------             ---------
Net Cash Flows From Operating Activities                                                        231,397                33,502
                                                                                               ---------             ---------

                     INVESTING ACTIVITIES
-------------------------------------------------------------
Construction Expenditures                                                                       (95,425)              (97,952)
Other                                                                                               607                     -
                                                                                               ---------             ---------
Net Cash Flows Used For Investing Activities                                                    (94,818)              (97,952)
                                                                                               ---------             ---------

                     FINANCING ACTIVITIES
-------------------------------------------------------------
Change in Short-term Debt-Affiliates                                                           (650,000)              200,000
Issuance of Long-term Debt                                                                      800,000               797,335
Retirement of Long-term Debt                                                                    (85,427)             (583,836)
Change in Advances to/from Affiliates, Net                                                     (153,038)              198,371
Retirement of Common Stock                                                                            -              (386,005)
Dividends Paid on Common Stock                                                                  (90,601)             (115,505)
Dividends Paid on Cumulative Preferred Stock                                                       (181)                 (181)
                                                                                               ---------             ---------
Net Cash Flows From (Used For) Financing Activities                                            (179,247)              110,179
                                                                                               ---------             ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                            (42,668)               45,729
Cash and Cash Equivalents at Beginning of Period                                                 85,420                10,909
                                                                                               ---------             ---------
Cash and Cash Equivalents at End of Period                                                      $42,752               $56,638
                                                                                               =========             =========
</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $117,427,000 and
$63,005,000 and for income taxes was $42,901,000 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 $45 million year-to-date and $22 million for the third
quarter primarily due to a $22 million write- down of inactivated power plants
in 2002. Additionally, year-to-date net income was increased as a result of a
Cumulative Effect of Accounting Changes of $3 million (see Note 2).

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

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

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Operating Income

Operating Income increased by $18 million primarily due to:

     o   Reliability Must Run (RMR) revenues from ERCOT of $17 million,
         which include both fuel recovery and a fixed cost component of $3
         million (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 revenues from risk management activities of $6 million.
     o   Decreased fuel and purchased electricity on a combined basis of
         $26 million due mainly to decreased KWH both generated and
         purchased because of reduced sales due partly to a 2% decline in
         cooling degree-days, and the effect of the 2002 ICR adjustments of
         $5 million (see "ICR Explanation" in Note 6 in the Annual Report
         as updated by the Current Report on Form 8-K dated May 14, 2003,
         for discussion of the ICR adjustments). KWH generation also
         decreased due to the inactivation of several plants in late 2002,
         offset in part by a 12% increase in per unit costs due to
         increases in natural gas prices.
     o   Reduced Other Operation expenses of $35 million resulting from the 2002
         write-down of inactivated power plants.
     o   Reduced Depreciation and Amortization of $4 million mainly from
         adjustments to prior years' excess earnings accruals under the Texas
         restructuring legislation due to a favorable Appeals Court ruling
         (see Note 4) and reduced depreciable plant due to the inactivation of
         several power plants in late 2002.

The increase in Operating Income was partially offset by:

     o   Decreased system sales, including those to REPs, of $25 million due
         mainly to lower KWH
     o   Revenues from ERCOT for various services, including balancing energy,
         which declined $3 million.
     o   The 2002 ICR adjustments that accounted for approximately $25 million
         of the decrease in revenue (See "ICR Explanation" in Note 6 in the
         Annual Report, as updated by the Current Report on Form 8-K dated May
         14, 2003, for discussion of the ICR adjustments.)
     o   Decreased delivery revenues of $7 million due partly to the decline
         in cooling degree-days.
     o   Reduced  wholesale base revenues of $6 million due to the loss of
         several large  wholesale  customers  whose contracts were not renewed.
     o   Increased provisions for rate refunds of $3 million in 2003.
     o   Increased Income Tax Expense (Credit) of $11 million due to increases
         in pre-tax operating book income.

Other Impacts on Earnings

Nonoperating Income increased $8 million primarily due to increases from risk
management activities and non-utility revenues associated with energy-related
construction projects for third parties.

Nonoperating Expense increased $2 million primarily due to higher non-utility
expenses associated with energy-related construction projects for third parties.

Nonoperating Income Tax Expense (Credit) increased $2 million due to higher
pre-tax nonoperating book income.


Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Operating Income

Operating Income increased by $34 million primarily due to:

     o   Reliability Must Run (RMR) revenues from ERCOT of $40 million
         which include both fuel recovery and a fixed cost component of $10
         million (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 revenues from risk management activities of $9 million.
     o   Revenues from ERCOT for various services, including balancing energy,
         which increased $8 million.
     o   Reduced Other Operation expenses of $41 million due mainly to the
         2002 write-down of inactivated power plants, along with slight
         decreases in customer, production and administrative expenses.
     o   Reduced Depreciation and Amortization of $8 million mainly from
         adjustments to prior years' excess earnings accruals under the
         Texas restructuring legislation due to a favorable Appeals Court
         ruling (See Note 4), and reduced depreciable plant due to the
         inactivation of several power plants in late 2002.
     o   Reduced Taxes Other Than Income Taxes of $3 million 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   The 2002 ICR adjustments that accounted for approximately $25
         million of the decrease in revenues (See "ICR Explanation" in Note
         6 in the Annual Report, as updated by the Current Report on Form
         8-K dated May 14, 2003, for discussion of the ICR adjustments.)
     o   Decreased delivery revenues of $7 million, due partly to decreased
         cooling and heating degree-days.
     o   Reduced  wholesale  base  revenues of $13 million due to the loss of
         several  large  wholesale  customers  whose  contracts expired and
         were not renewed.
     o   Increased provision for rate refunds of $12 million in 2003 (see "TNC
         Fuel Reconciliation" in Note 3).
     o   Increased fuel and purchased electricity on a combined basis of $4
         million. KWH generation decreased 32% partly due to decreased
         cooling degree-days of 7% and heating degree-days of 1%, but the
         per unit cost of fuel increased 9% due to increased natural gas
         prices. KWH purchased declined 9%, but the average cost increased
         9%, and the 2002 ICR adjustments served to decrease purchased
         power.
     o   Increased Income Tax Expense (Credit) of $22 million due to increases
         in pre-tax operating book income.

Other Impacts on Earnings

Nonoperating Income increased $34 million primarily due to increases from risk
management activities and non-utility revenues associated with energy-related
construction projects for third parties.

Nonoperating Expense increased $23 million primarily due to higher non-utility
expenses associated with energy-related construction projects for third parties.

Nonoperating Income Tax Expense (Credit) increased $3 million due to higher
pre-tax nonoperating book income.


Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 (see Note 2).

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

Credit Ratings

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

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

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. TNC had its secured debt downgraded from A2 to
A3 and unsecured debt downgraded from A3 to Baa1. The completion of this review
was a culmination of ratings action started during 2002. In March 2003, S&P
lowered AEP and our senior unsecured debt and mortgage bonds ratings from BBB+
to BBB.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2003
were:

  Issuances
  ---------

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

     Senior Unsecured Notes           $225               5.50         2013

  Retirements
  -----------

                None

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' effects.




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
                      Nine Months Ended September 30, 2003
                                 (in thousands)

        Domestic Power
        --------------

        Beginning Balance December 31, 2002                      $2,043
        (Gain) Loss from Contracts Realized/Settled
         During the Period (a)                                     (178)
        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)                                            4,518
        Changes in Fair Value of Risk Management  Contracts
         Allocated to Regulated Jurisdictions (e)                   445
                                                                 -------
        Total MTM Risk Management Contract Net Assets             6,848
        Net Non-Trading Related Derivative
         Contracts                                                  178
                                                                 -------
        Net Fair Value of Risk Management and  Derivative
        Contracts September 30, 2003                             $7,026
                                                                 =======


        (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 September 30, 2003

                                                     Remainder                                                    After
                                                       2003          2004        2005       2006       2007       2007       Total
                                                     ---------       ----        ----       ----       ----       -----      -----
                                                                                     (in thousands)
<C>                                                     <C>        <C>          <C>         <C>        <C>       <C>        <C>
     Prices Provided by Other External  Sources
     - OTC Broker Quotes (a)                            $148       $1,646         $727        $637     $151          $-     $3,309
     Prices Based on Models and Other
      Valuation Methods (b)                              247          598          379         459      506       1,350      3,539
                                                        -----      -------      -------     -------    -----     -------    -------
     Total                                              $395       $2,244       $1,106      $1,096     $657      $1,350     $6,848
                                                        =====      =======      =======     =======    =====     =======    =======
</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). In accordance with GAAP, all amounts are presented net of
related income taxes.

                Total Other Comprehensive Income (Loss) Activity
                      Nine Months Ended September 30, 2003

                                                               Domestic
                                                                Power
                                                               --------
                                                            (in thousands)
             Accumulated OCI, December 31, 2002                    $(15)
             Changes in Fair Value (a)                               77
             Reclassifications from OCI to Net
              Income (b)                                             53
                                                                   -----
             Accumulated OCI Derivative Gain  (Loss)
             September 30, 2003                                    $115
                                                                   =====

(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 $201 thousand gain.

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:


                 September 30, 2003                     December 31, 2002
                 ------------------                     -----------------
                  (in thousands)                         (in thousands)
              End  High  Average  Low                End   High  Average  Low
              ---  ----  -------  ---                ---   ----  -------  ---
             $106  $302   $139    $30                $48   $146    $52    $11


<PAGE>
<TABLE>
<CAPTION>


                                                          AEP TEXAS NORTH COMPANY
                                                          STATEMENTS OF OPERATIONS
                                      For the Three and Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                     Three Months Ended                    Nine Months Ended
                                                                     ------------------                    -----------------
                                                                  2003               2002               2003               2002
                                                                  ----               ----               ----               ----
                                                                                        (in thousands)

                 OPERATING REVENUES
------------------------------------------------------------
<C>                                                             <C>                 <C>               <C>                <C>
Electric Generation, Transmission and Distribution              $104,104             $ 62,041          $320,733           $155,375
Sales to AEP Affiliates                                           10,351               90,626            46,790            205,370
                                                                ---------            ---------         ---------          ---------
TOTAL                                                            114,455              152,667           367,523            360,745
                                                                ---------            ---------         ---------          ---------

                 OPERATING EXPENSES
------------------------------------------------------------
Fuel for Electric Generation                                       9,457                8,276            29,196             26,289
Fuel from Affiliates for Electric Generation                      14,390               15,498            31,392             55,307
Purchased Electricity for Resale                                  22,933               39,087            74,434             53,015
Purchased Electricity from AEP Affiliates                          2,486               12,552            38,280             34,761
Other Operation                                                   23,394               58,273            66,378            107,350
Maintenance                                                        4,552                5,389            14,705             16,795
Depreciation and Amortization                                      7,132               11,513            26,387             34,154
Taxes Other Than Income Taxes                                      5,281                5,718            14,746             17,545
Income Tax Expense (Credit)                                        7,411               (3,331)           21,478               (855)
                                                                ---------            ---------         ---------          ---------
TOTAL                                                             97,036              152,975           316,996            344,361
                                                                ---------            ---------         ---------          ---------

OPERATING INCOME (LOSS)                                           17,419                 (308)           50,527             16,384

Nonoperating Income                                               23,581               15,446            54,877             20,938
Nonoperating Expenses                                             15,220               13,639            43,892             20,898
Nonoperating Income Tax Expense (Credit)                           2,707                  599             3,188                (33)
Interest Charges                                                   5,726                5,093            16,290             15,983
                                                                ---------            ---------         ---------          ---------
Income (Loss) Before Cumulative Effect of Accounting Changes      17,347               (4,193)           42,034                474
Cumulative Effect of Accounting Changes (Net of Tax)                   -                    -             3,071                  -
                                                                ---------            ---------         ---------          ---------
NET INCOME (LOSS)                                                 17,347               (4,193)           45,105                474

Preferred Stock Dividend  Requirements                                26                   26                78                 78
                                                                ---------            ---------         ---------          ---------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                       $17,321              $(4,219)          $45,027               $396
                                                                =========            =========         =========          =========
</TABLE>

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

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

<PAGE>
<TABLE>
<CAPTION>



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


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

<C>                                                 <C>               <C>            <C>                <C>              <C>
JANUARY 1, 2002                                     $137,214          $2,351         $105,970                 $-         $245,535

Common Stock Dividends                                                                (20,247)                            (20,247)
Preferred Stock Dividends                                                                 (78)                                (78)
                                                                                                                         ---------
TOTAL                                                                                                                     225,210
                                                                                                                         ---------

       COMPREHENSIVE INCOME
-----------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Unrealized Gain on Cash Flow Hedges                                                                        17               17
NET INCOME                                                                                474                                 474
                                                                                                                         ---------
TOTAL COMPREHENSIVE INCOME                                                                                                    491
                                                    ---------         -------         --------          ---------        ---------
SEPTEMBER 30, 2002                                  $137,214          $2,351          $86,119                $17         $225,701
                                                    =========         =======        =========          =========        =========


JANUARY 1, 2003                                     $137,214          $2,351          $71,942           $(30,763)        $180,744
Common Stock Dividends                                                                 (4,970)                             (4,970)
Preferred Stock Dividends                                                                 (78)                                (78)
Capital Stock Gain                                                                          3                                   3
                                                                                                                         ---------
TOTAL                                                                                                                     175,699
                                                                                                                         ---------

       COMPREHENSIVE INCOME
------------------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Unrealized Gain on Cash Flow Hedges                                                                       130              130
   Unrealized Loss on Minimum Pension
    Liability                                                                                                 (7)              (7)
NET INCOME                                                                             45,105                              45,105
                                                                                                                         ---------
TOTAL COMPREHENSIVE INCOME                                                                                                 45,228
                                                    ---------         -------        ---------          ---------        ---------
SEPTEMBER 30, 2003                                  $137,214          $2,351         $112,002           $(30,640)        $220,927
                                                    =========         =======        =========          =========        =========

</TABLE>

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





<PAGE>
<TABLE>
<CAPTION>


                                                          AEP TEXAS NORTH COMPANY
                                                              BALANCE SHEETS
                                                                  ASSETS
                                                September 30, 2003 and December 31, 2002
                                                               (Unaudited)

                                                                                                 2003                    2002
                                                                                                 ----                    ----
                                                                                                        (in thousands)
                    ELECTRIC UTILITY PLANT
------------------------------------------------------------
<C>                                                                                           <C>                     <C>
Production                                                                                     $358,020                $353,087
Transmission                                                                                    266,468                 254,483
Distribution                                                                                    454,255                 445,486
General                                                                                         113,303                 111,679
Construction Work in Progress                                                                    31,171                  37,012
                                                                                              ----------              ----------
TOTAL                                                                                         1,223,217               1,201,747
Accumulated Depreciation and Amortization                                                       531,854                 521,792
                                                                                              ----------              ----------
TOTAL - NET                                                                                     691,363                 679,955
                                                                                              ----------              ----------

Other Property and Investments                                                                    1,167                   1,213
Long-term Risk Management Assets                                                                  6,214                   2,248

                        CURRENT ASSETS
------------------------------------------------------------
Cash and Cash Equivalents                                                                         2,742                   1,219
Advances to Affiliates                                                                           15,075                      -
Accounts Receivable:
  Customers                                                                                      62,254                  62,660
  Affiliated Companies                                                                           29,395                  43,632
  Allowance for Uncollectible Accounts                                                             (261)                 (5,041)
Fuel Inventory                                                                                    8,821                  12,677
Materials and Supplies                                                                           10,772                   9,574
Accrued Utility Revenues                                                                          5,888                   6,829
Risk Management Assets                                                                            5,154                   4,130
Prepayments and Other                                                                             1,243                   1,070
                                                                                              ----------              ----------
TOTAL                                                                                           141,083                 136,750
                                                                                              ----------              ----------

Regulatory Assets                                                                                42,426                  45,097
Deferred Charges                                                                                 30,321                  11,912

TOTAL ASSETS                                                                                   $912,574                $877,175
                                                                                              ==========              ==========
</TABLE>

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




<PAGE>
<TABLE>
<CAPTION>


                                                          AEP TEXAS NORTH COMPANY
                                                               BALANCE SHEETS
                                                       CAPITALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                             2003                    2002
                                                                                             ----                    ----
                                                                                                   (in thousands)
                    CAPITALIZATION
------------------------------------------------------------
<C>                                                                                         <C>                     <C>
Common Shareholder's Equity:
   Common Stock - $25 Par Value:
     Authorized - 7,800,000 Shares
     Outstanding - 5,488,560 Shares                                                         $137,214                $137,214
      Paid-in Capital                                                                          2,351                   2,351
      Accumulated Other Comprehensive Income (Loss)                                          (30,640)                (30,763)
      Retained Earnings                                                                      112,002                  71,942
                                                                                            ---------               ---------
Total Common Shareholder's Equity                                                            220,927                 180,744
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                 2,357                   2,367
Long-term Debt                                                                               332,686                 132,500
                                                                                            ---------               ---------
TOTAL                                                                                        555,970                 315,611
                                                                                            ---------               ---------

Other Noncurrent Liabilities                                                                  41,911                  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                                                                                      36,187                  32,714
 Affiliated Companies                                                                         32,196                  76,217
Customer Deposits                                                                                209                     117
Taxes Accrued                                                                                 11,769                   3,697
Interest Accrued                                                                               4,266                   2,776
Risk Management Liabilities                                                                    2,309                   3,801
Other                                                                                         13,040                  17,414
                                                                                            ---------               ---------
TOTAL                                                                                        124,012                 342,143
                                                                                            ---------               ---------

Deferred Income Taxes                                                                        119,802                 117,521
Deferred Investment Tax Credits                                                               20,370                  21,510
Long-term Risk Management Liabilities                                                          2,033                     557
Regulatory Liabilities and Deferred Credits                                                   48,476                  50,972
Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                        $912,574                $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
                                               Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                                               2003                  2002
                                                                                               ----                  ----
                                                                                                   (in thousands)
                  OPERATING ACTIVITIES
------------------------------------------------------------
<C>                                                                                           <C>                   <C>
Net Income                                                                                     $45,105                 $474
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Depreciation and Amortization                                                                26,387               34,154
   Write Down of Utility Plant Assets                                                                -               34,215
   Deferred Income Taxes                                                                           231              (14,139)
   Deferred Investment Tax Credits                                                              (1,140)                (953)
   Cumulative Effect of Accounting Changes                                                      (3,071)               -
   Mark-to-Market of Risk Management Contracts                                                  (4,786)              (2,863)
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                                      9,863              (41,364)
   Fuel, Materials and Supplies                                                                  2,658               (3,969)
   Accrued Utility Revenues                                                                        941                -
   Accounts Payable                                                                            (40,548)              (7,012)
   Taxes Accrued                                                                                 8,072               11,998
   Fuel Recovery                                                                                     -                9,161
   Deferred Property Taxes                                                                      (3,323)              (3,588)
Change in Other Assets                                                                         (13,093)             (13,603)
Change in Other Liabilities                                                                      7,308                  113
                                                                                              ---------             --------
Net Cash Flows From Operating Activities                                                        34,604                2,624
                                                                                              ---------             --------

                  INVESTING ACTIVITIES
------------------------------------------------------------
Construction Expenditures                                                                      (33,136)             (33,338)
Other                                                                                              595                  -
                                                                                              ---------             --------
Net Cash Flows Used For Investing Activities                                                   (32,541)             (33,338)
                                                                                              ---------             --------
                  FINANCING ACTIVITIES
------------------------------------------------------------
Change in Short-term Debt-Affiliates                                                          (125,000)                 -
Issuance of Long-term Debt                                                                     225,000                  -
Retirement of Long-term Debt                                                                         -              (95,799)
Retirement of Preferred Stock                                                                      (10)                 -
Change in Advances to/from Affiliates, Net                                                     (95,482)             144,726
Dividends Paid on Common Stock                                                                  (4,970)             (20,247)
Dividends Paid on Cumulative Preferred Stock                                                       (78)                 (78)
                                                                                              ---------             --------
Net Cash Flows From (Used For) Financing Activities                                               (540)              28,602
                                                                                              ---------             --------

Net Increase (Decrease) in Cash and Cash Equivalents                                             1,523               (2,112)
Cash and Cash Equivalents at Beginning of Period                                                 1,219                2,454
                                                                                              ---------             --------
Cash and Cash Equivalents at End of Period                                                      $2,742                 $342
                                                                                              =========             ========

</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $12,990,000 and
$13,061,000 and for income taxes was $16,410,000 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 nine months of 2003 increased $61 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. This increase was
partially offset by a $12 million decrease in net nonoperating income primarily
due to reduced gains from risk management activities and increased Interest
Charges of $5 million due to the effects of refinancing activities.

Net Income for the third quarter of 2003 decreased $8 million primarily due to
an $18 million increase in capacity charges included in Purchased Electricity
from AEP Affiliates partially offset by increased earnings from system sales and
increased net nonoperating income. 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.

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Operating Income

Operating Income for the third quarter of 2003 decreased by $14 million from
2002 primarily due to the following:

     o   An increase in purchased power and fuel expense of $45 million
         reflecting the $18 million increase in capacity charges described
         above, the increase in our relative share of the AEP Power Pool
         expenses and the recently increased cost of coal.
     o   A decline in retail sales of $8 million resulting from decreased
         residential sales reflecting the mild weather conditions combined
         with lower industrial sales reflecting the continued weak economy.
         Cooling degree days for the quarter decreased 25% from the prior
         period.
     o   An $11 million decrease due to reduced gains from risk management
         activities.

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

     o   An increase in system sales and transmission revenues totaling $29
         million reflecting an increase in the volume of AEP Power Pool
         transactions, as well as our relative share based on the higher
         allocation factor.
     o   An increase of $9 million in Sales to AEP Affiliates.
     o   A decrease in income taxes of $7 million primarily due to the decrease
         in pre-tax operating book income.

Other Impacts on Earnings

Nonoperating Income increased $1 million for the third quarter primarily due to
increased interest income on investments in the AEP Money Pool. The $2 million
decrease in Nonoperating Income Tax Expense for third quarter was primarily due
to a tax adjustment related to consolidated tax savings.

Interest Charges decreased $2 million for the third quarter primarily due to the
early retirement of First Mortgage Bonds in the second quarter of 2003 partially
offset by increased interest expense from a higher average balance of Senior
Unsecured Notes (see Financing Activities section below).

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Operating Income

Operating Income for the first nine months of 2003 was relatively flat compared
to the prior year.

The positive factors affecting Operating Income are as follows:

     o   System sales and transmission revenues increased $71 million over
         2002, due to increased system sales volume, as well as our
         relative share based on the higher allocation factor.
     o   An increase in Sales to AEP Affiliates of $28 million.
     o   A decrease in Depreciation and Amortization expense of $13 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.
     o   An increase in gains from risk management activities of $12 million.

These increases in Operating Income for the first nine months of 2003 were
offset by:

     o   An increase of $112 million in purchased power and fuel expense
         primarily due to a $41 million increase in capacity charges, the
         increase in our relative share of AEP Power Pool expenses and the
         recently increased cost of coal.
     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 severe storm damage in the first
         quarter of 2003.

Other Impacts on Earnings

Nonoperating Income decreased $24 million for the nine months ended September
30, 2003, primarily due to a decrease in gains from risk management activities.
Nonoperating Income Tax decreased $13 million for the nine months ended
September 30, 2003 due to a decrease in pre-tax nonoperating book income and a
tax adjustment related to consolidated tax savings.

Interest Charges increased $5 million for the nine months ended September 30,
2003, due to decreased AFUDC credits in 2003 compared to 2002 and call premiums
relating to retirement of First Mortgage Bonds and Installment Purchase
Contracts. (See Financing Activities).

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes of $77 million is due to the
implementation of SFAS 143 and EITF 02-03 (see Note 2).

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

Credit Ratings

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

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of our rating for unsecured debt from Baa1 to Baa2 and a downgrade of secured
ratings from A3 to Baa1. The completion of this review was a culmination of
ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.


Cash Flow

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

                                                                               2003               2002
                                                                               ----               ----
                                                                                   (in thousands)
           <C>                                                               <C>               <C>
           Cash and cash equivalents at beginning of period                    $4,285           $13,663
           Cash flow from (used for):
             Operating activities                                             404,828           229,160
             Investing activities                                            (187,969)         (171,831)
             Financing activities                                            (215,877)          (61,564)
                                                                             ---------         ---------
           Net increase (decrease) in cash and cash equivalents                   982            (4,235)
                                                                             ---------         ---------
           Cash and cash equivalents at end of period                          $5,267            $9,428
                                                                             =========         =========
</TABLE>

Operating Activities

Cash flow from operating activities increased $176 million primarily due to
decreases in various accounts receivable balances in the nine months ended
September 30, 2003.

Investing Activities

Construction expenditures in 2003 versus 2002 increased $15 million. The current
year expenditures of $190 million were focused primarily on projects to improve
service reliability for transmission and distribution, as well as environmental
upgrades.

Financing Activities

In 2003, we issued two series of Senior Unsecured Notes, each in the amount of
$200 million which were used to call First Mortgage Bonds and fund maturities.
Additionally, we incurred obligations of $100 million in Installment Purchase
Contracts which were used to redeem higher costing Installment Purchase
Contracts.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2003
were:

<TABLE>
<CAPTION>

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

             <C>                                <C>                <C>            <C>
             Senior Unsecured Notes             $200               3.60           2008
             Senior Unsecured Notes              200               5.95           2033
             Installment Purchase
                Contracts                        100               5.50           2022


</TABLE>

<TABLE>
<CAPTION>



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

             <C>                              <C>             <C>              <C>
             First Mortgage Bonds              $70              8.50            2022
             First Mortgage Bonds               30              7.80            2023
             First Mortgage Bonds               20              7.15            2023
             Installment Purchase
                Contracts                       10              7.875           2013
             Installment Purchase
                Contracts                       40              6.85            2022
             Installment Purchase
                Contracts                       50              6.60            2022
             Senior Unsecured Notes            100              7.20            2038
             Senior Unsecured Notes            100              7.30            2038
             Senior Unsecured Notes            125            Variable          2003
</TABLE>


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), we are involved in litigation regarding generating
plant emissions under the Clean Air Act. The 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. The 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 5 for
further discussion.

NOx Reductions

The 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 other
combustion control 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 $464 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, these costs would adversely affect future results of
operations, cash flows and possibly financial condition (see Note 5).

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 AEP's transmission
system to RTOs. Furthermore, legislation in certain states in which AEP
subsidiaries operate requires RTO participation.

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

In December 2002, we filed with the Virginia SCC for approval of our plan to
transfer functional control of our transmission assets to PJM. In February 2003,
Virginia enacted legislation that prohibited the transfer of transmission assets
in its jurisdiction to an RTO until, at the earliest, July 2004 and only with
the approval of Virginia SCC.

We are unable to predict the outcome of these regulatory actions and proceedings
or their impact on our transmission operations, results of operations and cash
flows or the timing and operation of RTOs (see Note 3).

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.

<TABLE>
<CAPTION>

                     Roll-Forward of MTM Risk Management Contract Net Assets
                            Nine Months Ended September 30, 2003
                                       (in thousands)
        Domestic Power
        --------------

        <C>                                                                     <C>
        Beginning Balance December 31, 2002                                      $96,852
        (Gain) Loss from Contracts Realized/Settled
         During the Period (a)                                                  (34,984)
        Fair Value of New Contracts When Entered Into
         During the Period (b)                                                        -
        Net Option Premiums Paid/(Received) (c)                                     265
        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)                                                            2,022
        Changes in Fair Value Risk Management Contracts
         Allocated to Regulated Jurisdictions (e)                                (1,030)
                                                                                --------
        Total MTM Risk Management Contract Net
         Assets                                                                  58,461
        Net Non-Trading Related Derivative
         Contracts                                                                1,561
                                                                                --------
        Net Fair Value of Risk Management and Derivative
         Contracts September 30, 2003                                           $60,022
                                                                                ========
</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, 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 September 30, 2003

                                                    Remainder                                                      After
                                                      2003          2004        2005       2006         2007       2007      Total
                                                    ---------       ----        ----       ----         ----       -----     -----
                                                                                 (in thousands)
<C>                                                  <C>         <C>          <C>         <C>         <C>        <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                                     $(291)         $53       $(266)         $-          $-         $-       $(504)
Prices Provided by Other External  Sources -
OTC Broker Quotes (a)                                 1,259       14,602       6,200       5,436       1,287          -      28,784
Prices Based on Models and Other  Valuation
Methods (b)                                           2,109        5,098       3,236       3,913       4,315      11,510     30,181
                                                     -------     --------     -------     -------     -------    --------   --------
Total                                                $3,077      $19,753      $9,170      $9,349      $5,602     $11,510    $58,461
                                                     =======     ========     ======      =======     =======    ========   ========
</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
                                                            Nine Months Ended September 30, 2003

                                                          Domestic          Foreign
                                                           Power            Currency            Interest Rate       Consolidated
                                                          --------          --------            -------------       ------------
                                                                                   (in thousands)
        <C>                                                 <C>              <C>                   <C>                <C>
        Accumulated OCI, December 31, 2002                  $(394)           $(190)                $(1,336)           $(1,920)
        Changes in Fair Value (a)                             785                -                    (719)                66
        Reclassifications from OCI to Net
         Income (b)                                           475                5                     226                706
                                                            ------           ------                --------           --------
        Accumulated OCI Derivative Gain (Loss)
         September 30, 2003                                  $866            $(185)                $(1,829)           $(1,148)
                                                            ======           ======                ========           ========
</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 $1,167 thousand gain.

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:


                 September 30, 2003                     December 31, 2002
                 ------------------                     -----------------
                  (in thousands)                         (in thousands)
              End  High  Average  Low                End   High  Average  Low
              ---  ----  -------  ---                ---   ----  -------  ---
             $800 $2,271  $1,046 $226              $1,289 $3,948 $1,412  $286



<PAGE>
<TABLE>
<CAPTION>



                                                 APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                     CONSOLIDATED STATEMENTS OF INCOME
                                      For the Three and Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                 Three Months Ended                         Nine Months Ended
                                                                 ------------------                         -----------------
                                                               2003                2002                  2003              2002
                                                               ----                ----                  ----              ----
                                                                                        (in thousands)
             OPERATING REVENUES
----------------------------------------------------------
<C>                                                          <C>                  <C>                <C>               <C>
Electric Generation, Transmission and Distribution           $428,667             $418,159           $1,297,255        $1,220,039
Sales to AEP Affiliates                                        54,944               46,250              167,335           138,990
                                                             ---------            ---------          -----------       -----------
TOTAL                                                         483,611              464,409            1,464,590         1,359,029
                                                             ---------            ---------          -----------       -----------

             OPERATING EXPENSES
----------------------------------------------------------
Fuel for Electric Generation                                  113,274              107,514              345,819           322,164
Purchased Electricity for Resale                               18,365               13,174               50,745            41,635
Purchased Electricity from AEP Affiliates                      92,857               58,395              257,382           177,892
Other Operation                                                64,065               67,255              192,806           197,631
Maintenance                                                    31,855               32,053              101,420            85,542
Depreciation and Amortization                                  46,501               47,692              128,574           141,373
Taxes Other Than Income Taxes                                  23,232               23,881               70,583            73,926
Income Taxes                                                   26,328               33,080               88,387            90,723
                                                             ---------            ---------          -----------       -----------
TOTAL                                                         416,477              383,044            1,235,716         1,130,886
                                                             ---------            ---------          -----------       -----------

OPERATING INCOME                                               67,134               81,365              228,874           228,143

Nonoperating Income                                             7,809                6,627                2,878            26,644
Nonoperating Expenses                                           4,217                4,865               10,219             9,170
Nonoperating Income Tax
 Expense (Credit)                                              (1,307)                 538               (7,491)            5,622
Interest Charges                                               26,318               28,642               89,520            84,099
                                                             ---------            ---------          -----------       -----------
Income Before Cumulative Effect
 of Accounting Changes                                         45,715               53,947              139,504           155,896
Cumulative Effect of Accounting Changes (Net of Tax)                -                    -               77,257                 -
                                                             ---------            ---------          -----------       -----------
NET INCOME                                                     45,715               53,947              216,761           155,896

Preferred Stock Dividend Requirements
 (Including Capital Stock Expense)                                703                  502                2,671             1,508
                                                             ---------            ---------          -----------       -----------

EARNINGS APPLICABLE TO COMMON STOCK                           $45,012              $53,445             $214,090          $154,388
                                                             =========            =========          ===========       ===========
</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
                                                           (in thousands)
                                                            (Unaudited)


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

<C>                                                 <C>            <C>             <C>                 <C>            <C>
JANUARY 1, 2002                                     $260,458       $715,786        $150,797               $(340)      $1,126,701

Common Stock Dividends                                                              (92,952)                             (92,952)
Preferred Stock Dividends                                                            (1,082)                              (1,082)
Capital Stock Expense                                                   426            (426)                                   -
                                                                                                                      -----------
TOTAL                                                                                                                  1,032,667
                                                                                                                      -----------

        COMPREHENSIVE INCOME
--------------------------------------------------
Other Comprehensive Income (Loss),
 Net of  Taxes:
  Unrealized Loss on Cash Flow Hedges                                                                    (1,387)          (1,387)
NET INCOME                                                                          155,896                              155,896
                                                                                                                      -----------
TOTAL COMPREHENSIVE INCOME                                                                                               154,509
                                                    ---------      ---------       ---------           ---------      -----------
SEPTEMBER 30, 2002                                  $260,458       $716,212        $212,233            $ (1,727)      $1,187,176
                                                    ---------      ---------       ---------           ---------      -----------



JANUARY 1, 2003                                     $260,458       $717,242        $260,439            $(72,082)      $1,166,057

Common Stock Dividends                                                              (96,200)                             (96,200)
Preferred Stock Dividends                                                              (801)                                (801)
Capital Stock Expense                                                 1,870          (1,870)                                  -
SFAS 71 Reapplication                                                   162                                                  162
                                                                                                                      -----------
TOTAL                                                                                                                  1,069,218
                                                                                                                      -----------

        COMPREHENSIVE INCOME
--------------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
  Unrealized Gain on Cash Flow Hedges                                                                       772              772
NET INCOME                                                                          216,761                              216,761
                                                                                                                      -----------
TOTAL COMPREHENSIVE INCOME                                                                                               217,533
                                                    ---------      ---------       ---------           ---------      -----------
SEPTEMBER 30, 2003                                  $260,458       $719,274        $378,329            $(71,310)      $1,286,751
                                                    =========      =========       =========           =========      ===========

</TABLE>

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



<PAGE>
<TABLE>
<CAPTION>


                                                    APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                            CONSOLIDATED BALANCE SHEETS
                                                                       ASSETS
                                                      September 30, 2003 and December 31, 2002
                                                                     (Unaudited)

                                                                                             2003                   2002
                                                                                             ----                   ----
                                                                                                    (in thousands)
                  ELECTRIC UTILITY PLANT
----------------------------------------------------------
<C>                                                                                      <C>                     <C>
Production                                                                               $2,286,567              $2,245,945
Transmission                                                                              1,236,108               1,218,108
Distribution                                                                              1,991,491               1,951,804
General                                                                                     280,309                 272,901
Construction Work in Progress                                                               254,387                 206,545
                                                                                         -----------             -----------
TOTAL                                                                                     6,048,862               5,895,303
Accumulated Depreciation and Amortization                                                 2,381,700               2,424,607
                                                                                         -----------             -----------
TOTAL - NET                                                                               3,667,162               3,470,696
                                                                                         -----------             -----------

Other Property and Investments                                                               49,356                  54,653
Long-term Risk Management Assets                                                             83,520                 115,748

                    CURRENT ASSETS
----------------------------------------------------------
Cash and Cash Equivalents                                                                     5,267                   4,285
Advances to Affiliates                                                                       34,434                      -
Accounts Receivable:
    Customers                                                                               110,481                 132,266
    Affiliated Companies                                                                     90,591                 122,665
    Miscellaneous                                                                            26,072                  28,629
    Allowance for Uncollectible Accounts                                                     (2,570)                (13,439)
Fuel Inventory                                                                               33,235                  53,646
Materials and Supplies                                                                       74,095                  59,886
Accrued Utility Revenues                                                                      7,822                  30,948
Risk Management Assets                                                                       57,957                  94,238
Prepayments and Other                                                                        16,833                  13,396
                                                                                         -----------             -----------
TOTAL                                                                                       454,217                 526,520
                                                                                         -----------             -----------

Regulatory Assets                                                                           402,559                 395,553
Deferred Charges                                                                             45,562                  64,677

TOTAL ASSETS                                                                             $4,702,376              $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
                                                       CAPITALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)


                                                                                                     2003               2002
                                                                                                     ----               ----
                                                                                                         (in thousands)
                      CAPITALIZATION
----------------------------------------------------------
<C>                                                                                              <C>                 <C>
Common Shareholder's Equity:
    Common Stock - No Par Value:
      Authorized - 30,000,000 Shares
      Outstanding - 13,499,500 Shares                                                              $260,458            $260,458
      Paid-in Capital                                                                               719,274             717,242
      Accumulated Other Comprehensive Income (Loss)                                                 (71,310)            (72,082)
      Retained Earnings                                                                             378,329             260,439
                                                                                                 -----------         -----------
Total Common Shareholder's Equity                                                                 1,286,751           1,166,057
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                       17,790              17,790
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption                             10,860              10,860
Long-term Debt                                                                                    1,802,332           1,738,854
                                                                                                 -----------         -----------
TOTAL                                                                                             3,117,733           2,933,561
                                                                                                 -----------         -----------

Other Noncurrent Liabilities                                                                        190,379             173,438

                   CURRENT LIABILITIES
----------------------------------------------------------
Long-term Debt Due Within One Year                                                                   51,008             155,007
Advances from Affiliates                                                                                  -              39,205
Accounts Payable:
   General                                                                                          120,319             141,546
   Affiliated Companies                                                                              61,670              98,374
Taxes Accrued                                                                                        47,182              29,181
Customer Deposits                                                                                    31,776              26,186
Interest Accrued                                                                                     42,791              22,437
Risk Management Liabilities                                                                          36,278              69,001
Other                                                                                                70,473              79,832
                                                                                                 -----------         -----------
TOTAL                                                                                               461,497             660,769
                                                                                                 -----------         -----------

Deferred Income Taxes                                                                               755,125             701,801
Deferred Investment Tax Credits                                                                      31,752              33,691
Long-term Risk Management Liabilities                                                                45,177              44,517
Regulatory Liabilities and Deferred Credits                                                         100,713              80,070
Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                             $4,702,376          $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
                                           For the Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                                                  2003                   2002
                                                                                                  ----                   ----
                                                                                                         (in thousands)
                   OPERATING ACTIVITIES
----------------------------------------------------------
<C>                                                                                             <C>                   <C>
Net Income                                                                                       $216,761              $155,896
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
    Cumulative Effect of Accounting Changes                                                       (77,257)                -
    Depreciation and Amortization                                                                 128,574               141,457
    Deferred Income Taxes                                                                           3,394                10,257
    Deferred Investment Tax Credits                                                                (1,940)               (3,295)
    Deferred Power Supply Costs, Net                                                               71,815                 -
    Mark to Market of Risk Management Contracts                                                    33,727               (27,710)
Changes in Certain Assets and Liabilities:
    Accounts Receivable, Net                                                                       45,547               (83,288)
    Fuel, Materials and Supplies                                                                    6,202                 5,176
    Accrued Utility Revenues                                                                       23,126                 7,547
    Accounts Payable                                                                              (57,931)              (26,948)
    Taxes Accrued                                                                                  18,001                39,660
    Interest Accrued                                                                               20,354                13,487
    Incentive Plan Accrued                                                                         (8,789)                -
    Rate Stabilization Deferral                                                                   (75,601)                -
Change in Other Assets                                                                             19,748                (7,697)
Change in Other Liabilities                                                                        39,097                 4,618
                                                                                                 ---------             ---------
Net Cash Flows From Operating Activities                                                          404,828               229,160
                                                                                                 ---------             ---------

                  INVESTING ACTIVITIES
----------------------------------------------------------
Construction Expenditures                                                                        (190,047)             (175,314)
Proceeds from Sale of Property and Other                                                            2,078                 3,483
                                                                                                 ---------             ---------
Net Cash Flows Used For Investing Activities                                                     (187,969)             (171,831)
                                                                                                 ---------             ---------

                  FINANCING ACTIVITIES
----------------------------------------------------------
Issuance of Long-term Debt                                                                        500,000               444,110
Change in Advances to/from Affiliates, Net                                                        (73,639)             (126,640)
Retirement of Long-term Debt                                                                     (545,237)             (285,000)
Dividends Paid on Common Stock                                                                    (96,200)              (92,952)
Dividends Paid on Cumulative Preferred Stock                                                         (801)               (1,082)
                                                                                                 ---------             ---------
Net Cash Flows Used For Financing Activities                                                     (215,877)              (61,564)
                                                                                                 ---------             ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                                  982                (4,235)
Cash and Cash Equivalents at Beginning of Period                                                    4,285                13,663
                                                                                                 ---------             ---------
Cash and Cash Equivalents at End of Period                                                         $5,267                $9,428
                                                                                                 =========             =========
</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $63,481,000 and
$68,305,000 and for income taxes was $47,419,000 and $38,425,000 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

The decrease in Net Income of $13 million in the third quarter of 2003 compared
to the third quarter of 2002 was primarily due to a $27 million decrease in
retail electricity sales and a $12 million decrease in revenues from risk
management activities, which were partially offset by a $4 million increase in
sales to AEP affiliated companies and a $23 million decrease in income taxes. As
a member of the AEP Power Pool, we share in the revenues and costs of marketing
and activities conducted by the AEP Power Pool on our behalf.

The decrease in Net Income of $4 million for the nine months ended September 30,
2003 compared to the same period in 2002 was primarily due to a $41 million
increase in fuel and purchased power expenses and a $28 million decrease in
revenues from risk management activities, partially offset by a $31 million
decrease in income taxes and a $27 million net-of-tax Cumulative Effect of
Accounting Changes.

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Operating Income

Operating Income decreased by $18 million primarily due to:

     o   Milder weather and a sluggish economy that resulted in decreased
         retail revenues of $27 million. Cooling degree days for the
         quarter decreased 36% from the prior period.
     o   A $10 million decrease in risk management income due to unfavorable
         market conditions and reduced activity.
     o   Increased purchased electricity of $10 million due to increased usage
         of the AEP Power Pool to meet load requirements.
     o   An increase of $5 million in Maintenance expense due to boiler
         overhaul work from scheduled and forced outages and
         maintenance of overhead lines resulting from severe storm damage.

The decrease in Operating Income was partially offset by:

     o   An increase of $4 million in Sales to AEP Affiliates.
     o   A decrease in Other Operation expense of $5 million primarily due
         to decreases in factored receivable expenses, AEP transmission
         equalization expenses and miscellaneous distribution expenses.
     o   A decrease in Income Taxes of $18 million primarily due to a decrease
         in pre-tax operating book income.

Other Impacts on Earnings

Nonoperating Income Tax Expense decreased $5 million primarily due to a tax
adjustment related to consolidated tax savings.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Operating Income

Operating Income decreased $23 million primarily due to:

     o   Milder spring and summer weather and a sluggish economy resulting
         in decreased retail revenues of $37 million. Cooling degree days
         have decreased 41% year-to-date from the prior period.
     o   An increase in the AEP system pool capacity charge of $5 million.
     o   A $13 million increase in Maintenance expense due primarily to
         boiler overhaul work from scheduled and forced outages and
         maintenance of overhead lines resulting from severe storm damage.
     o   A $10 million increase in fuel expense due to higher coal costs.
     o   An increase of $28 million in Purchased Electricity from AEP
         Affiliates due to increased load requirements.

The decrease in Operating Income was partially offset by:

     o   An increase of $20 million of Sales to AEP Affiliates and an increase
         of $25 million of sales to non-affiliates.
     o   A decrease in Other Operation expense of $12 million primarily due to
         decreases in factored receivable expenses, AEP transmission
         equalization expenses and miscellaneous distribution expenses.
     o   Income Taxes decreased by $17 million primarily due to a decrease in
         pre-tax operating book income.

Other Impacts on Earnings

Nonoperating Income decreased $22 million primarily due to a reduction of risk
management activities as a result of AEP's decision to exit wholesale markets
where it does not own assets.

Nonoperating Income Tax Credit increased due to a decrease in pre-tax
nonoperating book income and a tax adjustment related to consolidated tax
savings.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to the one-time, after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Note 2).

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

Credit Ratings

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

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

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

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

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2003
were:

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

             Senior Unsecured Notes        $250              5.50         2013
             Senior Unsecured Notes         250              6.60         2033



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

             First Mortgage Bonds              $2           8.70      2022
             First Mortgage Bonds              15           8.55      2022
             First Mortgage Bonds              14           8.40      2022
             First Mortgage Bonds              13           8.40      2022
             First Mortgage Bonds              13           6.80      2003
             First Mortgage Bonds              26           6.55      2004
             First Mortgage Bonds              26           6.75      2004
             First Mortgage Bonds              40           7.90      2023
             First Mortgage Bonds              33           7.75      2023
             First Mortgage Bonds              25           6.60      2003


  Intercompany Retirement of Debt Due to AEP
  ------------------------------------------

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

             Notes Payable                  $160            6.501        2006

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), we are involved in litigation regarding generating
plant emissions under the Clean Air Act. The 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. The 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 5 for
further discussion.

NOx Reductions

The 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 combustion control 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, these costs would adversely affect future results of operations, cash
flows and possibly financial condition. See Note 5 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
                        Nine Months Ended September 30, 2003
                                   (in thousands)
        Domestic Power
        --------------

        Beginning Balance December 31, 2002                            $65,117
        (Gain) Loss from Contracts Realized/Settled
         During the Period (a)                                         (23,524)
        Fair Value of New Contracts When Entered Into During
         the Period (b)                                                      -
        Net Option Premiums Paid/(Received) (c)                            149
        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)                                                  (5,681)
        Changes in Fair Value Risk Management Contracts
        Allocated to Regulated Jurisdictions (e)                             -
                                                                       --------
        Total MTM Risk Management Contract Net
          Assets                                                        32,926
        Net Non-Trading Related Derivative
          Contracts                                                        901
                                                                       --------
        Net Fair Value of Risk Management and Derivative
        Contracts September 30, 2003                                   $33,827
                                                                       ========


        (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 September 30, 2003

                                              Remainder                                                         After
                                                2003            2004        2005        2006        2007        2007      Total
                                              ---------         ----        ----        ----        ----        -----     -----
                                                                               (in thousands)
<C>                                            <C>            <C>          <C>         <C>         <C>         <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                               $(164)            $30       $(150)         $-          $-         $-        $(284)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                  709           8,224       3,492       3,061         725          -       16,211
Prices Based on Models and Other
 Valuation Methods (b)                          1,189           2,871       1,823       2,204       2,430       6,482      16,999
                                               -------        --------     -------     -------     -------     -------    --------

Total                                          $1,734         $11,125      $5,165      $5,265      $3,155      $6,482     $32,926
                                               =======        ========     =======     =======     =======     =======    ========
</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). In accordance with GAAP, all amounts are presented net of
related income taxes.

                Total Other Comprehensive Income (Loss) Activity
                      Nine Months Ended September 30, 2003

                                                            Domestic
                                                             Power
                                                            --------
                                                         (in thousands)
           Accumulated OCI, December 31, 2002                   $(267)
           Changes in Fair Value (a)                              484
           Reclassifications from OCI to Net
            Income (b)                                            271
                                                                ------
           Accumulated OCI Derivative Gain (Loss)
           September 30, 2003                                   $ 488
                                                                ======
(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 $851 thousand gain.

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:


                 September 30, 2003                     December 31, 2002
                 ------------------                     -----------------
                  (in thousands)                         (in thousands)
              End  High  Average  Low                End   High  Average  Low
              ---  ----  -------  ---                ---   ----  -------  ---
             $450 $1,279  $589   $127               $867  $2,654  $949   $192




<PAGE>
<TABLE>
<CAPTION>



                                        COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                CONSOLIDATED STATEMENTS OF INCOME
                                For the Three and Nine Months Ended September 30, 2003 and 2002
                                                          (Unaudited)

                                                                   Three Months Ended                   Nine Months Ended
                                                                   ------------------                   -----------------
                                                                  2003             2002               2003              2002
                                                                  ----             ----               ----              ----
                                                                                        (in thousands)
                OPERATING REVENUES
--------------------------------------------------------
<C>                                                              <C>               <C>             <C>               <C>
Electric Generation, Transmission and Distribution               $375,936         $404,568         $1,027,732        $1,038,254
Sales to AEP Affiliates                                            21,719           17,324             62,199            42,277
                                                                 ---------        ---------        -----------       -----------
TOTAL                                                             397,655          421,892          1,089,931         1,080,531
                                                                 ---------        ---------        -----------       -----------

                OPERATING EXPENSES
--------------------------------------------------------
Fuel for Electric Generation                                       50,355           47,228            146,422           135,942
Purchased Electricity for Resale                                    5,688            3,569             13,898            11,124
Purchased Electricity from AEP Affiliates                          93,486           85,228            263,225           235,432
Other Operation                                                    57,348           62,393            166,027           178,042
Maintenance                                                        19,630           14,878             56,801            44,068
Depreciation and Amortization                                      34,442           33,450            101,478            98,588
Taxes Other Than Income Taxes                                      34,970           37,570            101,532            97,176
Income Taxes                                                       30,543           48,543             70,787            87,538
                                                                 ---------        ---------        -----------       -----------
TOTAL                                                             326,462          332,859            920,170           887,910
                                                                 ---------        ---------        -----------       -----------

OPERATING INCOME                                                   71,193           89,033            169,761           192,621

Nonoperating Income (Loss)                                          4,169            5,360             (2,587)           19,751
Nonoperating Expenses                                                 550            1,014              2,944             1,432
Nonoperating Income Tax Expense (Credit)                              (84)           4,590             (5,231)            9,387
Interest Charges                                                   12,071           12,672             38,946            39,857
                                                                 ---------        ---------        -----------       -----------
Income Before Cumulative Effect of Accounting Changes              62,825           76,117            130,515           161,696
Cumulative Effect of Accounting Changes (Net of Tax)                    -               -              27,283                 -
                                                                 ---------        ---------        -----------       -----------
NET INCOME                                                         62,825           76,117            157,798           161,696

Preferred Stock Dividend Requirements (Including
Capital Stock Expense)                                                254              254                762             1,112
                                                                 ---------        ---------        -----------       -----------

EARNINGS APPLICABLE TO COMMON STOCK                               $62,571          $75,863           $157,036          $160,584
                                                                 =========        =========        ===========       ===========
</TABLE>


The common stock of CSPCo is wholly-owned by AEP.

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



<PAGE>
<TABLE>
<CAPTION>


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


                                                                                                   Accumulated Other
                                                       Common      Paid-in        Retained           Comprehensive
                                                       Stock       Capital        Earnings           Income (Loss)         Total
                                                       ------      -------        --------         -----------------       -----
<C>                                                   <C>           <C>              <C>                 <C>             <C>
JANUARY 1, 2002                                       $41,026       $574,369         $176,103                            $791,498

Common Stock Dividends Declared                                                       (65,300)                            (65,300)
Preferred Stock Dividends Declared                                                       (350)                               (350)
Capital Stock Expense                                                    762             (762)                                  -
                                                                                                                         ---------
                                                                                                                          725,848
                                                                                                                         ---------
           COMPREHENSIVE INCOME
---------------------------------------------------
Other Comprehensive Income, Net of Taxes:
  Unrealized Gain on Cash Flow Power Hedges                                                                  $326             326
 NET INCOME                                                                           161,696                             161,696
                                                                                                                         ---------
 TOTAL COMPREHENSIVE INCOME                                                                                               162,022
                                                      --------      ---------        ---------           ---------       ---------
SEPTEMBER 30, 2002                                    $41,026       $575,131         $271,387                $326        $887,870
                                                      --------      ---------        ---------           ---------       ---------



JANUARY 1, 2003                                       $41,026       $575,384         $290,611            $(59,357)       $847,664

Common Stock Dividends Declared                                                      (124,932)                           (124,932)
Capital Stock Expense                                                    762             (762)                                  -
                                                                                                                         ---------
                                                                                                                          722,732
                                                                                                                         ---------
           COMPREHENSIVE INCOME
---------------------------------------------------
Other Comprehensive Income,
  Net of Taxes:
    Unrealized Gain on Cash Flow Power Hedges                                                                 755             755
 NET INCOME                                                                           157,798                             157,798
                                                                                                                         ---------
 TOTAL COMPREHENSIVE INCOME                                                                                               158,553
                                                      --------      ---------        ---------           ---------       ---------
SEPTEMBER 30, 2003                                    $41,026       $576,146         $322,715            $(58,602)       $881,285
                                                      ========      =========        =========           =========       ---------
</TABLE>

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



<PAGE>
<TABLE>
<CAPTION>


                                                  COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                           CONSOLIDATED BALANCE SHEETS
                                                                      ASSETS
                                                    September 30, 2003 and December 31, 2002
                                                                   (Unaudited)

                                                                                                2003                  2002
                                                                                                ----                  ----
                                                                                                       (in thousands)
                   ELECTRIC UTILITY PLANT
--------------------------------------------------------
<C>                                                                                          <C>                    <C>
Production                                                                                   $1,601,987             $1,582,627
Transmission                                                                                    422,717                413,286
Distribution                                                                                  1,247,229              1,208,255
General                                                                                         158,810                165,025
Construction Work in Progress                                                                   107,581                 98,433
                                                                                             -----------            -----------
TOTAL                                                                                         3,538,324              3,467,626
Accumulated Depreciation and Amortization                                                     1,468,746              1,465,174
                                                                                             -----------            -----------
TOTAL - NET                                                                                   2,069,578              2,002,452
                                                                                             -----------            -----------

Other Property and Investments                                                                   31,840                 35,759
Long-term Risk Management Assets                                                                 47,039                 77,810

                       CURRENT ASSETS
--------------------------------------------------------
Cash and Cash Equivalents                                                                         4,909                  1,479
Advances to Affiliates, Net                                                                           -                 31,257
Accounts Receivable:
  Customers                                                                                      33,157                 49,566
  Affiliated Companies                                                                           40,385                 54,518
  Miscellaneous                                                                                  21,090                 22,005
  Allowance for Uncollectible Accounts                                                             (575)                  (634)
Fuel                                                                                             15,231                 24,844
Materials and Supplies                                                                           46,626                 40,339
Accrued Utility Revenues                                                                         16,963                 12,671
Risk Management Assets                                                                           32,664                 63,348
Prepayments and Other                                                                            10,458                  7,308
                                                                                             -----------            -----------
TOTAL                                                                                           220,908                306,701
                                                                                             -----------            -----------

Regulatory Assets                                                                               247,403                257,682
Deferred Charges                                                                                 35,047                 72,836

TOTAL ASSETS                                                                                 $2,651,815             $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
                                                       CAPITALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                              2003                    2002
                                                                                              ----                    ----
                                                                                                     (in thousands)
                     CAPITALIZATION
--------------------------------------------------------
<C>                                                                                       <C>                      <C>
Common Shareholder's Equity:
  Common Stock - No Par Value:
     Authorized - 24,000,000 Shares
     Outstanding - 16,410,426 Shares                                                         $41,026                  $41,026
     Paid-in Capital                                                                         576,146                  575,384
     Accumulated Other Comprehensive Income (Loss)                                           (58,602)                 (59,357)
     Retained Earnings                                                                       322,715                  290,611
                                                                                          -----------              -----------
Total Common Shareholder's Equity                                                            881,285                  847,664
                                                                                          -----------              -----------
Long-term Debt:
     Nonaffiliated                                                                           747,806                  418,626
     Affiliated                                                                                    -                  160,000
Total Long-term Debt                                                                         747,806                  578,626
                                                                                          -----------              -----------
TOTAL                                                                                      1,629,091                1,426,290
                                                                                          -----------              -----------

Other Noncurrent Liabilities                                                                  88,683                   95,460

                 CURRENT LIABILITIES
--------------------------------------------------------
Long-term Debt Due Within One Year - Nonaffiliated                                             5,000                   43,000
Short-term Debt - Affiliates                                                                       -                  290,000
Advances from Affiliates, Net                                                                151,575                        -
Accounts Payable - General                                                                    53,325                   89,736
Accounts Payable - Affiliated Companies                                                       43,603                   81,599
Taxes Accrued                                                                                 78,304                  112,172
Interest Accrued                                                                               7,744                    9,798
Risk Management Liabilities                                                                   20,432                   46,375
Other                                                                                         51,021                   36,790
                                                                                          -----------              -----------
TOTAL                                                                                        411,004                  709,470
                                                                                          -----------              -----------

Deferred Income Taxes                                                                        451,638                  437,771
Deferred Investment Tax Credits                                                               31,619                   33,907
Long-term Risk Management Liabilities                                                         25,444                   29,926
Deferred Credits and Regulatory Liabilities                                                   14,336                   20,416
Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                      $2,651,815               $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
                                           For the Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                                          2003                  2002
                                                                                          ----                  ----
                                                                                                 (in thousands)
                  OPERATING ACTIVITIES
--------------------------------------------------------
<C>                                                                                     <C>                    <C>
Net Income                                                                              $157,798               $161,696
Adjustments to Reconcile Net Income to Net Cash Flows
   From Operating Activities:
     Cumulative Effect of Accounting Changes                                             (27,283)                    -
     Depreciation and Amortization                                                       101,478                 98,666
     Deferred Income Taxes                                                                (3,942)                12,450
     Deferred Investment Tax Credits                                                      (2,288)                (2,335)
     Mark-to-Market of Risk Management Contracts                                          29,056                (21,033)
Changes in Certain Assets and Liabilities:
     Accounts Receivable, Net                                                             31,398                (33,529)
     Fuel, Materials and Supplies                                                          3,326                 (2,391)
     Accrued Utility Revenues                                                             (4,292)               (14,925)
     Prepayments and Other Current Assets                                                 (3,150)                (6,991)
     Accounts Payable                                                                    (74,407)               (10,506)
     Taxes Accrued                                                                       (33,868)                 5,597
     Interest Accrued                                                                     (2,054)                 1,485
     Deferred Property Tax                                                                46,478                 31,968
Change in Other Assets                                                                   (12,882)                (3,155)
Change in Other Liabilities                                                               (4,496)                10,733
                                                                                        ---------              ---------
Net Cash Flows From Operating Activities                                                 200,872                227,730
                                                                                        ---------              ---------

                INVESTING ACTIVITIES
--------------------------------------------------------
Construction Expenditures                                                                (98,032)               (88,101)
Proceeds from Sale of Property                                                               190                    730
                                                                                        ---------              ---------
Net Cash Flows Used For Investing Activities                                             (97,842)               (87,371)
                                                                                        ---------              ---------

                FINANCING ACTIVITIES
--------------------------------------------------------
Issuance of Long-term Debt                                                               500,000                160,000
Change in Advances to/from Affiliates, Net                                               182,832               (206,501)
Retirement of Long-term Debt - Nonaffiliated                                            (207,500)              (112,843)
Retirement of Long-term Debt - Affiliated                                               (160,000)              (200,000)
Retirement of Cumulative Preferred Stock                                                       -                (10,000)
Change in Short-term Debt - Affiliates                                                  (290,000)               290,000
Dividends Paid on Common Stock                                                          (124,932)               (65,300)
Dividends Paid on Cumulative Preferred Stock                                                   -                   (525)
                                                                                        ---------              ---------
Net Cash Flows Used For Financing Activities                                             (99,600)              (145,169)
                                                                                        ---------              ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                       3,430                 (4,810)
Cash and Cash Equivalents at Beginning of Period                                           1,479                 12,358
                                                                                        ---------              ---------
Cash and Cash Equivalents at End of Period                                                $4,909                 $7,548
                                                                                        =========              =========
</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $39,804,000 and
$37,204,000 and for income taxes was $48,955,000 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 third quarter of 2003, Net Income increased $2 million reflecting reduced
financing costs. Net Income increased $10 million including an unfavorable $3
million Cumulative Effect of Accounting Change in the first nine months of 2003
(see Note 2). For the nine months ended September 30, 2003, Net Income Before
Cumulative Effect of Accounting Change increased $13 million due to an
improvement in earnings primarily during the first quarter of 2003 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.
As a member of the AEP Power Pool, we share in the revenues and costs of
marketing and activities conducted by the AEP Power Pool on our behalf.

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Operating Income

Operating Income decreased less than $1 million primarily due to:

     o   Decreased retail revenues of $22 million due primarily to milder
         weather during the third quarter of 2003 and economic pressures on
         industrial customers. Cooling degree days declined approximately
         33% this year compared with last year. Industrial revenues dropped
         5% from last year.
     o   Increased Fuel for Electric Generation expense of $2 million
         reflecting an increase in the average cost of fuel.
     o   Increased Purchased Electricity from AEP Affiliates of $9 million due
         to purchasing more power from the AEP Power Pool to support wholesale
         sales to unaffiliated entities.

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

     o   Increased sales to AEP Affiliates of $6 million due to increased
         capacity revenue.
     o   Increased wholesale sales including system and power optimization
         sales, transmission revenues and risk management activities of $25
         million reflecting availability of AEP's generation and market
         conditions.
     o   A $3 million decrease in Maintenance  expense due to an insurance
         recovery for costs incurred related to an influx of fish at Cook Plant.
         See Significant Factors section below.

Other Impacts on Earnings

Interest Charges decreased $4 million in the third quarter primarily due to a
reduction in outstanding long-term debt of $255 million which was retired in May
2003 using lower rate short-term debt.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Operating Income

Operating Income increased $27 million primarily due to the following:

     o   Wholesale revenues increased $61 million reflecting market conditions.
     o   Sales to AEP Affiliates increased by $43 million due to more power
         being available for sale in 2003 and increased capacity revenues.
         In 2002, both units 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 versus one
         refueling outage in 2003.
     o   An $8 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   A $23 million decline in retail revenues reflecting milder summer
         weather and lower industrial sales reflecting economic pressure.
     o   Increased  Fuel for  Electric  Generation  expense of $33 million
         reflecting  an increase in the average  cost of fuel and increased
         generation.
     o   Increased Purchased Electricity from AEP Affiliates of $31 million
         due to higher power purchases from AEGCo and the AEP Power Pool in
         2003 compared to 2002 when outages at both units of the Rockport
         Plant decreased available power and purchases of replacement power
         during 2003 Cook forced outages.
     o   Increased Income Taxes of $11 million reflecting an increase in
         pre-tax income.

Other Impacts on Earnings

Nonoperating Income decreased $20 million year-to-date primarily due to lower
margins for power sold outside of AEP's traditional marketing area reflecting
AEP's plan to exit those risk management activities.

Interest Charges decreased $6 million year-to-date primarily due to a reduction
in outstanding long-term debt of $255 million which was retired in May 2003
using lower rate short-term debt.

Cumulative Effect of Accounting Change

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

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 nine months ended September 30, 2003 and 2002 were as follows:

<TABLE>
<CAPTION>

                                                                           2003                 2002
                                                                           ----                 ----
                                                                                 (in thousands)
           <C>                                                          <C>                   <C>
           Cash and cash equivalents at beginning of period               $3,237              $16,804
           Cash flow from (used for):
             Operating activities                                        191,018              161,460
             Investing activities                                       (106,546)             (91,360)
             Financing activities                                        (83,634)             (77,902)
                                                                        ---------             --------
           Net increase (decrease) in cash and cash equivalents              838               (7,802)
                                                                        ---------             --------
           Cash and cash equivalents at end of period                     $4,075               $9,002
                                                                        =========             ========

</TABLE>

Operating Activities

Operating activities during the first nine months of 2003 provided $30 million
more cash than during 2002 largely due to the year-over-year increase in net
income of $10 million and a $51 million increase in the change in mark-to-market
of risk management contracts offset by a $43 million decrease in accrued taxes.

Investing Activities

Cash flows used for investing activities during the first nine months of 2003
were $107 million compared to $91 million during 2002. The primary reason for
the year-over-year variance was a construction expenditures increase of $16
million. Construction expenditures for the nuclear plant and transmission and
distribution assets are to upgrade or replace equipment and improve reliability.

Financing Activities

Financing activities for the nine months ended September 30, 2003 used $6
million more than 2002 primarily due to dividends paid on common stock as none
were paid in 2002.

Financing Activity

Long-term debt issuances and retirements (using short-term debt) during the
first nine months of 2003 were:

  Issuances
  ---------

                None

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

             First Mortgage Bonds       $  75              8.50       2022
             First Mortgage Bonds          15              7.35       2023
             Junior Debentures             40              8.00       2026
             Junior Debentures            125              7.60       2038

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), we are involved in litigation regarding generating
plant emissions under the Clean Air Act. The 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. The 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 5 for
further discussion.

NOx Reductions

The 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 combustion control 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, these
costs would adversely affect future results of operations, cash flows and
possibly financial condition. See Note 5 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
                         Nine Months Ended September 30, 2003
                                   (in thousands)
        Domestic Power
        --------------
        Beginning Balance December 31, 2002                          $70,861
        (Gain) Loss from Contracts Realized/Settled
         During the Period (a)                                       (19,968)
        Fair Value of New Contracts When Entered Into
         During the Period (b)                                          -
        Net Option Premiums Paid/(Received) (c)                          164
        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)                                                  (928)
        Changes in Fair Value Risk Management Contracts
         Allocated to Regulated Jurisdictions (e)                     (9,928)
                                                                     --------
        Total MTM Risk Management Contract Net
         Assets                                                       35,340
        Net Non-Trading Related Derivative
         Contracts                                                       985
                                                                     --------
        Net Fair Value of Risk Management and Derivative
         Contracts September 30, 2003                                $36,325
                                                                     ========


        (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 September 30, 2003

                                                  Remainder                                                    After
                                                    2003         2004         2005       2006        2007      2007       Total
                                                  ---------      ----         ----       ----        ----      -----      -----
                                                                              (in thousands)
<C>                                                 <C>         <C>          <C>        <C>        <C>         <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                                    $(180)         $32       $(164)        $-         $-          $-      $(312)
Prices Provided by Other External Sources -
 OTC Broker Quotes (a)                                 812        9,067       3,827      3,356        795           -      17,857
Prices Based on Models and Other Valuation
 Methods (b)                                           821        2,790       1,998      2,416      2,664       7,106      17,795
                                                    -------     --------     -------    -------    -------     -------    --------
Total                                               $1,453      $11,889      $5,661     $5,772     $3,459      $7,106     $35,340
                                                    =======     ========     =======    =======    =======     =======    ========

</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). In accordance with GAAP, all amounts are presented net of
related income taxes.

                Total Other Comprehensive Income (Loss) Activity
                      Nine Months Ended September 30, 2003

                                                                 Domestic
                                                                  Power
                                                                --------
                                                              (in thousands)
             Accumulated OCI, December 31, 2002                   $(286)
             Changes in Fair Value (a)                              526
             Reclassifications from OCI to Net
              Income (b)                                            295
                                                                  ------
             Accumulated OCI Derivative Gain (Loss)
              September 30, 2003                                   $535
                                                                  ======

(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 $933 thousand gain.

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:


                 September 30, 2003                     December 31, 2002
                 ------------------                     -----------------
                  (in thousands)                         (in thousands)
              End  High  Average  Low                End   High  Average  Low
              ---  ----  -------  ---                ---   ----  -------  ---
             $494 $1,402  $646   $140               $927  $2,840  $1,016 $206


<PAGE>
<TABLE>
<CAPTION>


                                           INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                 CONSOLIDATED STATEMENTS OF INCOME
                                 For the Three and Nine Months Ended September 30, 2003 and 2002
                                                            (Unaudited)

                                                                     Three Months Ended                      Nine Months Ended
                                                                     ------------------                      -----------------
                                                                   2003                2002               2003              2002
                                                                   ----                ----               ----              ----
                                                                                           (in thousands)
               OPERATING REVENUES
-------------------------------------------------------
<C>                                                              <C>                 <C>              <C>                <C>
Electric Generation, Transmission and Distribution               $356,003            $353,897         $1,022,296          $982,565
Sales to AEP Affiliates                                            67,001              60,517            196,212           153,127
                                                                 ---------           ---------        -----------        ----------
TOTAL                                                             423,004             414,414          1,218,508         1,135,692
                                                                 ---------           ---------        -----------        ----------

               OPERATING EXPENSES
-------------------------------------------------------
Fuel for Electric Generation                                       67,588              65,904            206,445           173,223
Purchased Electricity for Resale                                    9,058               6,706             22,375            17,386
Purchased Electricity from AEP Affiliates                          68,653              59,846            207,904           176,463
Other Operation                                                   109,106             108,457            319,019           340,556
Maintenance                                                        38,518              41,668            112,480           112,291
Depreciation and Amortization                                      43,453              42,081            130,020           125,817
Taxes Other Than Income Taxes                                      15,698              16,698             44,668            52,794
Income Taxes                                                       14,688              16,050             41,136            29,930
                                                                 ---------           ---------        -----------        ----------
TOTAL                                                             366,762             357,410          1,084,047         1,028,460
                                                                 ---------           ---------        -----------        ----------

OPERATING INCOME                                                   56,242              57,004            134,461           107,232

Nonoperating Income                                                19,335              17,899             36,240            56,452
Nonoperating Expenses                                              18,130              12,875             43,965            35,285
Nonoperating Income Tax Expense (Credit)                              821               2,999             (4,479)            3,887
Interest Charges                                                   19,510              23,717             64,603            70,648
                                                                 ---------           ---------        -----------        ----------
Net Income Before Cumulative Effect of Accounting
 Change                                                            37,116              35,312             66,612            53,864
Cumulative Effect of Accounting Change
  (Net of Tax)                                                         -                   -              (3,160)                -
                                                                 ---------           ---------        -----------        ----------
NET INCOME                                                         37,116              35,312             63,452            53,864

Preferred Stock Dividend Requirements
 (Including Capital Stock Expense)                                    118               1,145              2,390             3,453
                                                                 ---------           ---------        -----------        ----------

EARNINGS APPLICABLE TO COMMON STOCK                               $36,998             $34,167            $61,062           $50,411
                                                                 =========           =========        ===========        ==========
</TABLE>

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

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

<PAGE>
<TABLE>
<CAPTION>



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


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

<C>                                                    <C>           <C>             <C>               <C>              <C>
JANUARY 1, 2002                                        $56,584       $733,216         $74,605           $(3,835)          $860,570

Capital Contributions from Parent Company                             125,000                                              125,000
Preferred Stock Dividends                                                              (3,352)                              (3,352)
Capital Stock Expense                                                     310            (100)                                 210
                                                                                                                        -----------
                                                                                                                           982,428
                                                                                                                        -----------
          COMPREHENSIVE INCOME
------------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Cash Flow Interest Rate Hedge                                                                          3,835              3,835
   Unrealized Gain on Cash Flow Power Hedges                                                                349                349
NET INCOME                                                                             53,864                               53,864
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                  58,048
                                                       --------      ---------       ---------         ---------        -----------
SEPTEMBER 30, 2002                                     $56,584       $858,526        $125,017              $349         $1,040,476
                                                       ========      =========       =========         =========        ===========



JANUARY 1, 2003                                        $56,584       $858,560        $143,996          $(40,487)        $1,018,653

Common Stock Dividends                                                                (30,000)                             (30,000)
Preferred Stock Dividends                                                              (2,289)                              (2,289)
Capital Stock Expense                                                     101            (101)                                   -
                                                                                                                        -----------
                                                                                                                           986,364
                                                                                                                        -----------
          COMPREHENSIVE INCOME
------------------------------------------------
Other Comprehensive Income,
  Net of Taxes:
    Unrealized Gain on Cash Flow Power Hedges                                                               821                821
NET INCOME                                                                             63,452                               63,452
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                  64,273
                                                       --------      ---------       ---------         ---------        -----------
SEPTEMBER 30, 2003                                     $56,584       $858,661        $175,058          $(39,666)        $1,050,637
                                                       ========      =========       =========         =========        ===========

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



<PAGE>
<TABLE>
<CAPTION>


                                           INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                   CONSOLIDATED BALANCE SHEETS
                                                             ASSETS
                                             September 30, 2003 and December 31, 2002
                                                           (Unaudited)

                                                                                                2003                     2002
                                                                                                ----                     ----
                                                                                                         (in thousands)
                ELECTRIC UTILITY PLANT
-------------------------------------------------------
<C>                                                                                          <C>                      <C>
Production                                                                                   $2,872,210               $2,768,463
Transmission                                                                                    992,046                  971,599
Distribution                                                                                    947,186                  921,835
General (including nuclear fuel)                                                                269,550                  220,137
Construction Work in Progress                                                                   163,884                  147,924
                                                                                             -----------              -----------
TOTAL                                                                                         5,244,876                5,029,958
Accumulated Depreciation and Amortization                                                     2,719,346                2,568,604
                                                                                             -----------              -----------
TOTAL - NET                                                                                   2,525,530                2,461,354
                                                                                             -----------              -----------

Nuclear Decommissioning and Spent Nuclear Fuel
 Disposal Trust Funds                                                                           945,372                  870,754
Long-term Risk Management Assets                                                                 51,574                   83,265
Other Property and Investments                                                                  110,921                  120,941

                   CURRENT ASSETS
-------------------------------------------------------
Cash and Cash Equivalents                                                                         4,075                    3,237
Advances to Affiliates                                                                                -                  191,226
Accounts Receivable:
     Customers                                                                                   55,735                   67,333
     Affiliated Companies                                                                        84,914                  122,489
     Miscellaneous                                                                               19,420                   30,468
     Allowance for Uncollectible Accounts                                                          (568)                    (578)
Fuel                                                                                             25,014                   32,731
Materials and Supplies                                                                          105,757                   95,552
Risk Management Assets                                                                           36,271                   68,148
Prepayments and Other                                                                            13,503                   18,410
                                                                                             -----------              -----------
TOTAL                                                                                           344,121                  629,016
                                                                                             -----------              -----------

Regulatory Assets                                                                               265,205                  348,212
Deferred Charges                                                                                 51,709                   73,649

TOTAL ASSETS                                                                                 $4,294,432               $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
                                                       CAPITALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                                2003                   2002
                                                                                                ----                   ----
                                                                                                       (in thousands)
                     CAPITALIZATION
-------------------------------------------------------
<C>                                                                                         <C>                    <C>
Common Shareholder's Equity:
  Common Stock - No Par Value:
     Authorized - 2,500,000 Shares
     Outstanding - 1,400,000 Shares                                                            $56,584                $56,584
     Paid-in Capital                                                                           858,661                858,560
     Accumulated Other Comprehensive Income (Loss)                                             (39,666)               (40,487)
     Retained Earnings                                                                         175,058                143,996
                                                                                            -----------            -----------
Total Common Shareholder's Equity                                                            1,050,637              1,018,653
Cumulative Preferred Stock - Not Subject to Mandatory Redemption                                 8,101                  8,101
Liability for Cumulative Preferred Stock - Subject to Mandatory
 Redemption                                                                                     63,445                 64,945
Long-term Debt                                                                               1,188,337              1,587,062
                                                                                            -----------            -----------
TOTAL                                                                                        2,310,520              2,678,761
                                                                                            -----------            -----------

               OTHER NONCURRENT LIABILITIES
-------------------------------------------------------
Asset Retirement Obligations                                                                   543,688                      -
Nuclear Decommissioning                                                                              -                620,672
Other                                                                                          128,957                138,965
                                                                                            -----------            -----------
TOTAL                                                                                          672,645                759,637
                                                                                            -----------            -----------

                   CURRENT LIABILITIES
-------------------------------------------------------
Long-term Debt Due Within One Year                                                             180,000                 30,000
Advances from Affiliates                                                                        13,929                      -
Accounts Payable:
    General                                                                                     81,366                125,048
    Affiliated Companies                                                                        41,666                 93,608
Taxes Accrued                                                                                   43,415                 71,559
Interest Accrued                                                                                23,674                 21,481
Risk Management Liabilities                                                                     23,541                 48,568
Other                                                                                          111,791                101,051
                                                                                            -----------            -----------
TOTAL                                                                                          519,382                491,315
                                                                                            -----------            -----------

Deferred Income Taxes                                                                          316,515                356,197
Deferred Investment Tax Credits                                                                 92,205                 97,709
Deferred Gain on Sale and Leaseback -
 Rockport Plant Unit 2                                                                          71,105                 73,885
Long-term Risk Management Liabilities                                                           27,979                 32,261
Deferred Credits and Regulatory Liabilities                                                    284,081                 97,426
Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                        $4,294,432             $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 STATEMENTS OF CASH FLOWS
                                           For the Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                                            2003                  2002
                                                                                            ----                  ----
                                                                                                  (in thousands)
                 OPERATING ACTIVITIES
-------------------------------------------------------
<C>                                                                                       <C>                   <C>
Net Income                                                                                 $63,452               $53,864
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
     Cumulative Effect of Accounting Change                                                  3,160                    -
     Depreciation and Amortization                                                         130,020               125,881
     Deferral of Incremental Nuclear Refueling Outage Expenses, Net                         (4,049)              (38,103)
     Unrecovered Fuel and Purchased Power Costs                                             28,126                28,126
     Amortization of Nuclear Outage Costs                                                   30,000                30,000
     Deferred Income Taxes                                                                 (17,767)               (6,885)
     Deferred Investment Tax Credits                                                        (5,504)               (5,534)
     Mark-to-Market of Risk Management Contracts                                            30,661               (20,358)
Changes in Certain Assets and Liabilities:
     Accounts Receivable, Net                                                               60,211              (115,027)
     Fuel, Materials and Supplies                                                           (2,488)                1,155
     Accounts Payable                                                                      (95,624)               79,400
     Taxes Accrued                                                                         (28,144)               14,734
     Rent Accrued - Rockport Plant Unit 2                                                   18,464                18,464
Change in Other Assets                                                                     (15,379)              (31,715)
Change in Other Liabilities                                                                 (4,121)               27,458
                                                                                          ---------             ---------
Net Cash Flows From Operating Activities                                                   191,018               161,460
                                                                                          ---------             ---------

                INVESTING ACTIVITIES
-------------------------------------------------------
Construction Expenditures                                                                 (108,201)              (92,387)
Other                                                                                        1,655                 1,027
                                                                                          ---------             ---------
Net Cash Flows Used For Investing Activities                                              (106,546)              (91,360)
                                                                                          ---------             ---------

                FINANCING ACTIVITIES
-------------------------------------------------------
Capital Contributions from Parent                                                                -               125,000
Issuance of Long-term Debt                                                                       -                49,648
Retirement of Cumulative Preferred Stock                                                    (1,500)                 (424)
Retirement of Long-term Debt                                                              (255,000)             (250,000)
Change in Advances to/from Affiliates, Net                                                 205,155                 1,214
Dividends Paid on Common Stock                                                             (30,000)                    -
Dividends Paid on Cumulative Preferred Stock                                                (2,289)               (3,340)
                                                                                          ---------             ---------
Net Cash Flows Used For Financing Activities                                               (83,634)              (77,902)
                                                                                          ---------             ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                           838                (7,802)
Cash and Cash Equivalents at Beginning of Period                                             3,237                16,804
                                                                                          ---------             ---------
Cash and Cash Equivalents at End of Period                                                  $4,075              $  9,002
                                                                                          =========             =========
</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $59,359,000 and
$63,987,000 and for income taxes was $79,880,000 and $21,225,000 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 third quarter of 2003 increased $0.5 million from the
corresponding quarter in 2002 due to improved earnings from system sales and
transmission revenues. Net Income for the nine months ended September 30, 2003
decreased $1 million from the prior year due to the loss from the Cumulative
Effect of Accounting Change of $1 million (see Note 2). Income Before Cumulative
Effect of Accounting Change for the first nine months of 2003 was essentially
flat compared to the prior year period as improved earnings from system sales
and transmission revenues were offset by decreased net nonoperating income. As a
member of the AEP Power Pool, we share in the revenues and costs of marketing
and activities conducted on our behalf by the AEP Power Pool.

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Operating Income

Operating Income for the third quarter of 2003 increased $2 million primarily
due to:

     o   Increases  in system  sales  and  transmission  revenues  of $5
         million  and an  increase  in gains  from risk  management activities
         of $3 million.
     o   A decrease in Income Taxes of $2 million primarily due to state income
         tax accrual adjustments.

The increases in Operating Income were partially offset by:

     o   A decline in retail sales of $2 million in the third quarter of
         2003 resulting from decreased residential sales reflecting the
         mild weather conditions, despite a rate increase to recover the
         cost of emission control equipment (see Note 3). Cooling degree
         days were down 32% for the third quarter of 2003 compared to the
         prior year quarter. Lower industrial sales reflecting the
         continued weak economy also contributed to the decline in retail
         sales.
     o   An increase in purchased power of $4 million necessary to support
         system sales.
     o   An increase in Depreciation and Amortization of $2 million
         reflecting the completion and implementation of new capital
         projects in the third quarter of 2003, as well as the
         implementation of the SCR technology at the Big Sandy plant in the
         second quarter of 2003.

Other Impacts on Earnings

Nonoperating Income for the third quarter of 2003 was relatively flat.
Nonoperating Income Tax Expense for the quarter increased $1 million for the
third quarter of 2003 primarily due to changes in certain book versus tax
differences accounted for on a flow-through basis.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Operating Income

Operating Income for the nine months ended September 30, 2003 increased $8
million primarily due to:

     o   An  increase in system  sales and  transmission  revenues  of $12
         million  and an  increase in gains from risk management activities of
         $8 million.
     o   A decrease in Other Operation expense of $2 million from 2002 due to
         decreased  engineering  expenses and lower employee benefit expenses.

The increases in Operating Income were partially offset by:

     o   A decline in industrial sales of $4 million reflecting the continued
         weak economy.
     o   An increase in Depreciation and Amortization of $4 million
         reflecting the depreciation on the capital projects implemented in
         2003 as discussed above, as well as the implementation of an
         enterprise-wide software application in mid-2002.
     o   Increases in Purchased Electricity from AEP Affiliates of $16
         million necessary to support sales during the Big Sandy plant
         shutdown for the NOx reduction upgrades. The outage resulted in a
         decrease in net generation leading to a $6 million decrease in
         fuel expense that partly offset the increased purchased power
         expense. In addition, energy purchases increased from the Rockport
         Plant based on plant availability, as required by the unit power
         agreement with AEGCo, an affiliated company. The unit power
         agreement with AEGCo provides for our purchase of 15% of the total
         output of the two unit 2,600-MW capacity Rockport Plant.

Other Impacts on Earnings

Nonoperating Income for the first nine months of 2003 decreased $9 million
primarily due to reduced gains from risk management activities compared to the
prior year. Nonoperating Income Tax Expense for the first nine months of 2003
decreased $2 million primarily due to a decrease in pre-tax nonoperating book
income.

Cumulative Effect of Accounting Change

The Cumulative Effect of Accounting Change of $1 million is due to the
implementation of EITF 02-3 (see Note 2).

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

Credit Ratings

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

                                            Moody's       S&P         Fitch
                                            -------       ---         -----
         First Mortgage Bonds               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


Long-term debt issuances and retirements during the first nine months of 2003
were:

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

         Senior Unsecured Notes            $75              5.625          2032

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

             Junior Debentures               $40            8.72           2025





  Intercompany Retirements of Debt Due to AEP
  -------------------------------------------

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

             Notes Payable                  $15             4.336          2003

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

NOx Reductions

The 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 other
combustion control technology to reduce NOx emissions at our Big Sandy plant
commenced operation to comply with these rules.

The capital expenditures for the SCR and other combustion control technology
totaled $179 million through September 30, 2003. In 2003, the KPSC granted
recovery of approximately $18 million annually (see Note 3). See Note 5 for
further discussion of emissions control technology.

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 transmission
system to RTOs. Further, legislation in certain states in which AEP subsidiaries
operate requires RTO participation.

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

In December 2002, we filed with KPSC for approval of our plan to transfer
functional control of our transmission assets to PJM. 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. In August 2003, AEP sought and received
rehearing of the KPSC's order, allowing us to file additional evidence in this
proceeding.

We are unable to predict the outcome of these regulatory actions and proceedings
or their impact on our transmission operations, results of operations and cash
flows or the timing and operation of RTOs (see Note 3).

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
                        Nine Months Ended September 30, 2003
                                   (in thousands)

        Domestic Power
        --------------
        Beginning Balance December 31, 2002                         $24,998
        (Gain) Loss from Contracts  Realized/Settled
         During the Period (a)                                       (7,926)
        Fair Value of New Contracts When Entered Into
         During the Period (b)                                            -
        Net Option Premiums Paid/(Received) (c)                          60
        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)                                                  601
        Changes in Fair Value Risk Management Contracts
         Allocated to Regulated Jurisdictions (e)                    (2,685)
                                                                    --------
        Total MTM Risk Management Contract Net Assets                13,304
        Net Non-Trading Related Derivative
         Contracts                                                      361
                                                                    --------
        Net Fair Value of Risk Management and Derivative
         Contracts September 30, 2003                               $13,665
                                                                    ========

         (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 September 30, 2003

                                           Remainder                                                         After
                                              2003            2004         2005        2006        2007      2007         Total
                                           ---------          ----         ----        ----        ----      -----        -----
                                                                               (in thousands)
<C>                                           <C>           <C>          <C>         <C>         <C>        <C>         <C>
Prices Actively Quoted - Exchange
 Traded Contracts                             $(66)            $12         $(60)         $-          $-         $-        $(114)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)               288           3,322        1,411       1,237         293         -         6,551
Prices Based on Models and Other
 Valuation Methods (b)                         480           1,160          736         890         982      2,619        6,867
                                              -----         -------      -------     -------     -------    -------     --------
Total                                         $702          $4,494       $2,087      $2,127      $1,275     $2,619      $13,304
                                              =====         =======      =======     =======     =======    =======     ========
</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). In accordance with GAAP, all amounts are presented net of
related income taxes.

<TABLE>
<CAPTION>


                                           Total Other Comprehensive Income (Loss) Activity
                                                  Nine Months Ended September 30, 2003

                                                              Domestic
                                                                Power             Interest Rate            Consolidated
                                                              --------            -------------            ------------
                                                                                  (in thousands)
     <C>                                                        <C>                    <C>                     <C>
     Accumulated OCI,  December 31, 2002                        $(103)                 $425                    $322
     Changes in Fair Value (a)                                    192                     -                     192
     Reclassifications from OCI to Net
      Income (b)                                                  108                   (65)                     43
                                                                ------                 -----                   -----
     Accumulated OCI Derivative Gain (Loss) September
      30, 2003                                                   $197                  $360                    $557
                                                                ======                 =====                   =====
</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 $430 thousand gain.

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:


                 September 30, 2003                     December 31, 2002
                 ------------------                     -----------------
                  (in thousands)                         (in thousands)
              End  High  Average  Low                End   High  Average  Low
              ---  ----  -------  ---                ---   ----  -------  ---
             $182  $517   $238    $51               $333  $1,019  $364    $74

<PAGE>
<TABLE>
<CAPTION>


                                                           KENTUCKY POWER COMPANY
                                                            STATEMENTS OF INCOME
                                      For the Three and Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                       Three Months Ended                  Nine Months Ended
                                                                       ------------------                  -----------------
                                                                     2003              2002              2003             2002
                                                                     ----              ----              ----             ----
                                                                                           (in thousands)
                OPERATING REVENUES
--------------------------------------------------------
<C>                                                                <C>                <C>             <C>                <C>
Electric Generation, Transmission and Distribution                 $93,500            $87,720         $281,755           $264,154
Sales to AEP Affiliates                                             10,193             10,091           29,496             25,006
                                                                   --------           --------        ---------          ---------
TOTAL                                                              103,693             97,811          311,251            289,160
                                                                   --------           --------        ---------          ---------

              OPERATING EXPENSES
--------------------------------------------------------
Fuel for Electric Generation                                        19,608             19,747           52,994             59,084
Purchased Electricity for Resale                                       738                 24              719                 26
Purchased Electricity from AEP Affiliates                           34,723             31,440          108,289             92,747
Other Operation                                                     12,519             12,932           36,351             37,902
Maintenance                                                          6,671              7,168           20,597             19,795
Depreciation and Amortization                                       10,693              8,330           28,653             24,856
Taxes Other Than Income Taxes                                        2,300              1,904            6,742              6,407
Income Taxes                                                         3,344              5,147           13,011             12,190
                                                                   --------           --------        ---------          ---------
TOTAL                                                               90,596             86,692          267,356            253,007
                                                                   --------           --------        ---------          ---------

OPERATING INCOME                                                    13,097             11,119           43,895             36,153

Nonoperating Income (Loss)                                           1,329              1,712           (1,636)             6,907
Nonoperating Expenses                                                  212                707              554                701
Nonoperating Income Tax Expense (Credit)                               370               (801)          (1,114)               929
Interest Charges                                                     7,343              6,931           21,202             19,944
                                                                   --------           --------        ---------          ---------
Income Before Cumulative Effect
 of Accounting Change                                                6,501              5,994           21,617             21,486
Cumulative Effect of Accounting Change
 (Net of Tax)                                                            -                  -           (1,134)                 -
                                                                   --------           --------        ---------          ---------
NET INCOME                                                          $6,501             $5,994          $20,483            $21,486
                                                                   ========           ========        =========          =========
</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
                                                                (in thousands)
                                                                 (Unaudited)


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

<C>                                                    <C>           <C>              <C>                 <C>            <C>
JANUARY 1, 2002                                        $50,450       $158,750         $48,833             $(1,903)       $256,130

Common Stock Dividends                                                                (21,132)                            (21,132)
                                                                                                                         ---------
TOTAL                                                                                                                     234,998
                                                                                                                         ---------

        COMPREHENSIVE INCOME
------------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Unrealized Gain on Cash Flow Hedges                                                                      1,519           1,519
NET INCOME                                                                             21,486                              21,486
                                                                                                                         ---------
TOTAL COMPREHENSIVE INCOME                                                                                                 23,005
                                                       --------      ---------        --------            --------       ---------
SEPTEMBER 30, 2002                                     $50,450       $158,750         $49,187               $(384)       $258,003
                                                       ========      =========        ========            ========       =========



JANUARY 1, 2003                                        $50,450       $208,750         $48,269             $(9,451)       $298,018

Common Stock Dividends                                                                (16,448)                            (16,448)
                                                                                                                         ---------
TOTAL                                                                                                                     281,570
                                                                                                                         ---------

        COMPREHENSIVE INCOME
------------------------------------------------
Other Comprehensive Income,
  Net of Taxes:
   Unrealized Gain on Cash Flow Hedges                                                                        235             235
NET INCOME                                                                             20,483                              20,483
                                                                                                                         ---------
TOTAL COMPREHENSIVE INCOME                                                                                                 20,718
                                                       --------      ---------        --------            --------       ---------
SEPTEMBER 30, 2003                                     $50,450       $208,750         $52,304             $(9,216)       $302,288
                                                       ========      =========        ========            ========       =========
</TABLE>

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




<PAGE>
<TABLE>
<CAPTION>


                                                          KENTUCKY POWER COMPANY
                                                              BALANCE SHEETS
                                                                  ASSETS
                                                  September 30, 2003 and December 31, 2002
                                                               (Unaudited)

                                                                                                    2003                  2002
                                                                                                    ----                  ----
                                                                                                          (in thousands)
                  ELECTRIC UTILITY PLANT
--------------------------------------------------------
<C>                                                                                             <C>                    <C>
Production                                                                                        $457,231               $275,121
Transmission                                                                                       380,112                373,639
Distribution                                                                                       422,127                414,281
General                                                                                             67,071                 67,449
Construction Work in Progress                                                                       17,067                165,129
                                                                                                -----------            -----------
TOTAL                                                                                            1,343,608              1,295,619
Accumulated Depreciation and Amortization                                                          401,887                397,304
                                                                                                -----------            -----------
TOTAL - NET                                                                                        941,721                898,315
                                                                                                -----------            -----------

Other Property and Investments                                                                       6,684                  6,904
Long-term Risk Management Assets                                                                    19,006                 29,871

                     CURRENT ASSETS
--------------------------------------------------------
Cash and Cash Equivalents                                                                              760                  2,304
Accounts Receivable:
  Customers                                                                                         17,395                 22,044
  Affiliated Companies                                                                              14,281                 23,802
  Miscellaneous                                                                                      4,637                  2,889
  Allowance for Uncollectible Accounts                                                                (757)                  (192)
Fuel                                                                                                 9,702                 10,817
Materials and Supplies                                                                              17,855                 16,127
Accrued Utility Revenues                                                                             4,963                  5,301
Accrued Tax Benefit                                                                                   -                     1,253
Risk Management Assets                                                                              13,196                 24,320
Prepayments and Other                                                                                2,825                  2,127
                                                                                                -----------            -----------
TOTAL                                                                                               84,857                110,792
                                                                                                -----------            -----------

Regulatory Assets                                                                                  105,039                101,976
Deferred Charges                                                                                    14,110                 16,818

TOTAL ASSETS                                                                                    $1,171,417             $1,164,676
                                                                                                ===========            ===========
</TABLE>

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




<PAGE>
<TABLE>
<CAPTION>


                                                           KENTUCKY POWER COMPANY
                                                               BALANCE SHEETS
                                                       CAPATALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                               2003                2002
                                                                                               ----                ----
                                                                                                    (in thousands)
                    CAPITALIZATION
--------------------------------------------------------
<C>                                                                                        <C>                 <C>
Common Shareholder's Equity:
  Common Stock - $50 Par Value:
    Authorized - 2,000,000 Shares
    Outstanding - 1,009,000 Shares                                                            $50,450             $50,450
    Paid-in Capital                                                                           208,750             208,750
    Accumulated Other Comprehensive Income (Loss)                                              (9,216)             (9,451)
    Retained Earnings                                                                          52,304              48,269
                                                                                           -----------         -----------
Total Common Shareholder's Equity                                                             302,288             298,018
                                                                                           -----------         -----------
Long-term Debt:
    Nonaffiliated                                                                             427,578             391,632
    Affiliated                                                                                 60,000              60,000
                                                                                           -----------         -----------
Total Long-term Debt                                                                          487,578             451,632
                                                                                           -----------         -----------
TOTAL                                                                                         789,866             749,650
                                                                                           -----------         -----------

Other Noncurrent Liabilities                                                                   25,228              27,319

                 CURRENT LIABILITIES
--------------------------------------------------------
Long-term Debt Due Within One Year  - Affiliated                                                  -                15,000
Advances from Affiliates                                                                       42,195              23,386
Accounts Payable:
  General                                                                                      28,019              46,515
  Affiliated Companies                                                                         22,911              44,035
Customer Deposits                                                                               9,452               8,048
Interest Accrued                                                                                8,949               6,471
Taxes Accrued                                                                                     202                   -
Risk Management Liabilities                                                                     8,256              17,803
Other                                                                                          11,353              14,322
                                                                                           -----------         -----------
TOTAL                                                                                         131,337             175,580
                                                                                           -----------         -----------

Deferred Income Taxes                                                                         197,121             178,313
Deferred Investment Tax Credits                                                                 8,284               9,165
Long-term Risk Management Liabilities                                                          10,281              11,488
Regulatory Liabilities and Deferred Credits                                                     9,300              13,161
Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                       $1,171,417          $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
                                           For the Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)



                                                                                                    2003                   2002
                                                                                                    ----                   ----
                                                                                                           (in thousands)
              OPERATING ACTIVITIES
--------------------------------------------------------
<C>                                                                                                <C>                  <C>
Net Income                                                                                         $20,483               $21,486
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Cumulative Effect of Accounting Change                                                            1,134                     -
   Depreciation and Amortization                                                                    28,653                24,856
   Deferred Income Taxes                                                                            16,020                 7,461
   Deferred Investment Tax Credits                                                                    (880)                 (886)
   Deferred Fuel Costs, Net                                                                           (772)                2,081
   Mark-to-Market of Risk Management Contracts                                                       9,950               (13,161)
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                                         12,987               (13,559)
   Fuel, Materials and Supplies                                                                       (613)                  484
   Accrued Utility Revenues                                                                            338                (1,382)
   Accounts Payable                                                                                (39,620)               20,715
   Taxes Accrued                                                                                     1,455                (3,360)
Change in Other Assets                                                                              (2,792)               (2,154)
Change in Other Liabilities                                                                            (61)               12,238
                                                                                                   --------             ---------
Net Cash Flows From Operating Activities                                                            46,282                54,819
                                                                                                   --------             ---------

              INVESTING ACTIVITIES
--------------------------------------------------------
Construction Expenditures                                                                          (71,154)             (100,677)
Proceeds from Sales of Property and Other                                                              967                   182
                                                                                                   --------             ---------
Net Cash Flow Used for Investing Activities                                                        (70,187)             (100,495)
                                                                                                   --------             ---------
              FINANCING ACTIVITIES
--------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated                                                          75,000                     -
Issuance of Long-term Debt - Affiliated                                                                  -               123,843
Retirement of Long-term Debt - Nonaffiliated                                                       (40,000)              (84,500)
Retirement of Long-term Debt - Affiliated                                                          (15,000)                   -
Change in Advances to/from Affiliates, Net                                                          18,809                26,391
Dividends Paid                                                                                     (16,448)              (21,132)
                                                                                                   --------             ---------
Net Cash Flows From Financing Activities                                                            22,361                44,602
                                                                                                   --------             ---------

Net Decrease in Cash and Cash Equivalents                                                           (1,544)               (1,074)
Cash and Cash Equivalents at Beginning of Period                                                     2,304                 1,947
                                                                                                   --------             ---------
Cash and Cash Equivalents at End of Period                                                            $760                  $873
                                                                                                   ========             =========
</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $17,925,000 and
$19,560,000 in 2003 and 2002, respectively. Cash (received) paid for income
taxes was $(7,605,000) and $7,025,000 in 2003 and 2002, respectively. There were
no noncash acquisitions under capital lease in 2003. Noncash acquisitions under
capital leases in 2002 were $22,000.

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


<PAGE>

                         OHIO POWER COMPANY CONSOLIDATED
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Effective July 1, 2003, we consolidated JMG Funding, LP (JMG) as a result of the
implementation of FIN 46. See Note 2, "New Accounting Pronouncements and
Cumulative Effect of Accounting Changes," and Note 8, "Leases," for further
discussion of the effects of FIN 46.

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

Net Income for the quarter decreased $10 million due primarily to mild summer
weather and increased interest charges related to new issuances of debt. Net
Income increased $120 million year-to-date including $125 million Cumulative
Effect of Accounting Changes in the first quarter of 2003 (see Note 2). Net
Income Before Cumulative Effect of Accounting Changes decreased $5 million
year-to-date primarily due to decreased revenues from risk management
activities. 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 risk
management transactions.

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Operating Income

Operating Income decreased $3 million for the third quarter primarily due to the
following:

     o   Retail revenues decreased $10 million due primarily to milder
         weather during the third quarter 2003 and economic pressures on
         industrial customers. Cooling degree days were 36% less in the
         third quarter this year compared with the third quarter of last
         year. Industrial revenues dropped 5% from the third quarter of
         last year.
     o   Risk management income decreased $13 million due primarily to
         unfavorable market conditions and reduced activity.
     o   Third quarter Fuel for Electric Generation expense increased $7
         million due primarily to an increase of 10% in MWHs generated, which
         was sold to the AEP Power Pool.
     o   Maintenance expense increased $7 million due primarily to boiler
         overhaul work coupled with increased expense in maintaining
         overhead lines.

The decrease in Operating Income was partially offset by the following:

     o   Affiliated sales increased $34 million. The increase is the result
         of optimizing our generation capacity and selling our excess
         generated power to the AEP Power Pool.
     o   Income Taxes decreased $7 million primarily due to a decrease in
         pre-tax operating book income offset in part by changes in certain
         book versus tax differences accounted for on a flow-through basis.

Other Impacts of Earnings

Nonoperating Income increased $9 million for the third quarter due primarily to
the reduction in accruals for costs associated with coal companies sold prior to
2003.

Interest charges increased $15 million for the third quarter due primarily to
the replacement of lower cost floating-rate short-term debt with higher cost
fixed-rate longer-term debt.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
----------------------------------------------------------------------------
30, 2002
--------

Operating Income

Operating Income increased $31 million year to date primarily due to the
following:

     o   Revenues from non-affiliated system sales increased $25 million
         and affiliated sales increased $90 million. The increase in
         non-affiliated system sales is the result of the increase in
         volume of AEP Power Pool Sales allocated to us for the first nine
         months of 2003. The increase in affiliated sales is the result of
         optimizing our generation capacity and selling our excess
         generated power to the AEP Power Pool.
     o   Other Operation expenses decreased due primarily to a $7 million
         pre-tax adjustment to the workers' compensation reserve for coal
         companies sold in July 2001 and a $4 million decrease primarily
         due to a decrease in OPCo's portion of the total AEP Transmission
         Equalization payments.

The increase in Operating Income was partially offset by the following:

     o   Year-to-date  Fuel for  Electric  Generation  expense  increased  $22
         million due  primarily to an increase of 8.5% in MWHs generated.
     o   Maintenance expense increased $37 million due primarily to boiler
         overhaul work coupled with increased expense in maintaining
         overhead lines due to storm damage in southern Ohio.
     o   Purchased  Electricity  from AEP Affiliates increased $16 million as
         a result of an increased volume of purchases from the
         AEP Power Pool for the first nine months of 2003.

Other Impacts on Earnings

Nonoperating Income decreased $22 million year-to-date due primarily to lower
margins for risk management activities 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.

Interest charges increased $14 million due primarily to the replacement of lower
cost floating-rate short-term debt with higher cost fixed-rate longer-term debt.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to the one-time after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Note 2).

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 nine months ended September 30, 2003 and 2002 were as follows:
<TABLE>
<CAPTION>

                                                                                 2003                 2002
                                                                                 ----                 ----
                                                                                      (in thousands)
           <C>                                                                 <C>                <C>
           Cash and cash equivalents at beginning of period                      $5,285             $8,848
           Cash flow from (used for):
             Operating activities                                               232,482            446,138
             Investing activities                                              (160,244)          (218,813)
             Financing activities                                               (70,810)          (228,221)
                                                                               ---------          ---------
           Net increase (decrease) in cash and cash equivalents                   1,428               (896)
                                                                               ---------          ---------

           Cash and cash equivalents at end of period                            $6,713             $7,952
                                                                               =========          =========
</TABLE>

Operating Activities

Cash flow from operating activities for the nine months ended September 30, 2003
decreased $214 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 due
primarily to a $60 million decrease in construction expenditures.

Financing Activities

Cash flow used for financing activities for the first nine months of 2003 used
$157 million less than the first nine months 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.
     o   We issued two series of Senior Unsecured Notes, each in the amount of
         $225 million each in July 2003.
     o   The change in Advances to/from Affiliates, net decreased $133 million
         from prior period.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2003
were:

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

             Senior Unsecured Notes   $250              5.50            2013
             Senior Unsecured Notes    250              6.60            2033
             Senior Unsecured Notes    225              4.85            2014
             Senior Unsecured Notes    225              6.375           2033





  Retirements
  -----------

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

             First Mortgage Bonds      $30              6.75            2003


  Intercompany Retirements of Debt Due to AEP
  -------------------------------------------

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

             Notes Payable            $240              6.501           2006
             Notes Payable              60              4.336           2003

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), we are involved in litigation regarding generating
plant emissions under the Clean Air Act. The 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. The 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
5 for further discussion.

NOx Reductions

The 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 other
combustion control 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 $531 million to $860 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, these costs would adversely affect future results of
operations, cash flows and possibly financial condition. See Note 5 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
                           Nine Months Ended September 30, 2003
                                     (in thousands)

        Domestic Power
        --------------

        Beginning Balance December 31, 2002                            $94,106
        (Gain) Loss from Contracts Realized/Settled
         During  the Period (a)                                        (36,790)
        Fair Value of New Contracts When Entered Into
         During the Period (b)                                               -
        Net Option Premiums Paid/(Received) (c)                            199
        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)                                                  (3,694)
        Changes in Fair Value of Risk Management Contracts
         Allocated to Regulated Jurisdictions (e)                            -
                                                                       --------
        Total MTM Risk Management Contract Net Assets                   49,662
        Net Non-Trading Related Derivative
         Contracts                                                       1,207
                                                                       --------
        Net Fair Value of Risk Management and Derivative
         Contracts September 30, 2003                                  $50,869
                                                                       ========


        (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 September 30, 2003

                                              Remainder                                                         After
                                                2003           2004        2005        2006         2007        2007         Total
                                              ---------        ----        ----        ----         ----        -----        -----
                                                                                  (in thousands)
<C>                                             <C>          <C>          <C>         <C>          <C>          <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                                $(219)          $40       $(200)         $-           $-           $-       $(379)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                 4,218        13,368       4,668       4,093          969            -      27,316
Prices Based on Models and Other
 Valuation Methods (b)                           1,588         3,839       2,437       2,946        3,249        8,666      22,725
                                                -------      --------     -------     -------      -------      -------    --------
Total                                           $5,587       $17,247      $6,905      $7,039       $4,218       $8,666     $49,662
                                                =======      ========     =======     =======      =======      =======    ========
</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 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
                                    Nine Months Ended September 30, 2003

                                                      Domestic            Foreign
                                                       Power              Currency          Consolidated
                                                      --------            --------          ------------
                                                                       (in thousands)
    <C>                                                 <C>                <C>                 <C>
    Accumulated OCI, December 31, 2002                  $(354)             $(384)              $(738)
    Changes in Fair Value (a)                             645                 -                  645
    Reclassifications from OCI to Net
     Income (b)                                           361                 10                 371
                                                        ------             ------              ------
    Accumulated OCI Derivative Gain (Loss)
     September 30, 2003                                  $652              $(374)               $278
                                                        ======             ======              ======

</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 $1,125 thousand gain.

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:


                 September 30, 2003                     December 31, 2002
                 ------------------                     -----------------
                  (in thousands)                         (in thousands)
              End  High  Average  Low                End   High  Average  Low
              ---  ----  -------  ---                ---   ----  -------  ---
             $602 $1,710  $788   $170              $1,150 $3,521 $1,259   $255



<PAGE>
<TABLE>
<CAPTION>


                                                       OHIO POWER COMPANY CONSOLIDATED
                                                     CONSOLIDATED STATEMENTS OF INCOME
                                      For the Three and Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                    Three Months Ended                    Nine Months Ended
                                                                    ------------------                    -----------------
                                                                 2003                2002              2003               2002
                                                                 ----                ----              ----               ----
                                                                                         (in thousands)
            OPERATING REVENUES
----------------------------------------------
<C>                                                            <C>                 <C>              <C>                <C>
Electric Generation, Transmission and Distribution             $418,083            $444,298         $1,256,862         $1,251,288
Sales to AEP Affiliates                                         147,235             113,276            438,473            348,303
                                                               ---------           ---------        -----------        -----------
TOTAL                                                           565,318             557,574          1,695,335          1,599,591
                                                               ---------           ---------        -----------        -----------

            OPERATING EXPENSES
----------------------------------------------
Fuel for Electric Generation                                    155,222             148,480            462,316            439,913
Purchased Electricity for Resale                                 15,219              15,841             52,064             49,042
Purchased Electricity from AEP Affiliates                        23,693              20,375             70,905             54,867
Other Operation                                                  92,376              94,893            269,998            290,982
Maintenance                                                      38,598              32,011            127,466             90,956
Depreciation and Amortization                                    67,365              62,144            189,140            185,941
Taxes Other Than Income Taxes                                    45,582              46,341            132,350            135,472
Income Taxes                                                     33,465              40,279            118,597            110,446
                                                               ---------           ---------        -----------        -----------
TOTAL                                                           471,520             460,364          1,422,836          1,357,619
                                                               ---------           ---------        -----------        -----------

OPERATING INCOME                                                 93,798              97,210            272,499            241,972

Nonoperating Income                                              20,567              11,157             21,350             43,057
Nonoperating Expenses                                             8,840               6,241             26,565             17,501
Nonoperating Income Tax Expense (Credit)                          1,646               3,638             (1,446)             7,986
Interest Charges                                                 33,512              18,230             73,736             59,885
                                                               ---------           ---------        -----------        -----------
Income Before Cumulative Effect of
 Accounting Changes                                              70,367              80,258            194,994            199,657
Cumulative Effect of Accounting Changes
 (Net of Tax)                                                         -                   -            124,632                  -
                                                               ---------           ---------        -----------        -----------
NET INCOME                                                       70,367              80,258            319,626            199,657

Preferred Stock Dividend Requirements                               286                 315                915                944
                                                               ---------           ---------        -----------        -----------

EARNINGS APPLICABLE TO COMMON STOCK                             $70,081             $79,943           $318,711           $198,713
                                                               =========           =========        ===========        ===========

</TABLE>

The common stock of OPCo is wholly-owned by AEP.

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

<PAGE>
<TABLE>
<CAPTION>



                                                     OHIO POWER COMPANY CONSOLIDATED
                                         CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
                                                          COMPREHENSIVE INCOME
                                                            (in thousands)
                                                              (Unaudited)



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

<C>                                                  <C>           <C>              <C>                 <C>            <C>
JANUARY 1, 2002                                      $321,201       $462,483        $401,297               $(196)      $1,184,785

Common Stock Dividends                                                               (97,746)                             (97,746)
Preferred Stock Dividends                                                               (944)                                (944)
                                                                                                                       -----------
                                                                                                                        1,086,095
                                                                                                                       -----------
       COMPREHENSIVE INCOME
----------------------------------------------
Other Comprehensive Income (Loss)
  Net of Taxes:
    Unrealized Gain on Cash Flow Hedges                                                                      242              242
NET INCOME                                                                           199,657                              199,657
                                                                                                                       -----------
TOTAL COMPREHENSIVE INCOME                                                                                                199,899
                                                     ---------     ---------        ---------           ---------      -----------
SEPTEMBER 30, 2002                                   $321,201       $462,483        $502,264                 $46       $1,285,994
                                                     =========     =========        =========           =========      ===========



JANUARY 1, 2003                                      $321,201       $462,483        $522,316            $(72,886)      $1,233,114

Common Stock Dividends                                                              (125,800)                            (125,800)
Preferred Stock Dividends                                                               (915)                                (915)
Capital Stock Expense                                                      1                                                    1
                                                                                                                       -----------
TOTAL                                                                                                                   1,106,400
                                                                                                                       -----------

       COMPREHENSIVE INCOME
----------------------------------------------
Other Comprehensive Income (Loss)
  Net of Taxes:
    Unrealized Gain on Cash Flow Hedges                                                                    1,016            1,016
    Minimum Pension Liability                                                                              5,625            5,625
NET INCOME                                                                           319,626                              319,626
                                                                                                                       -----------
TOTAL COMPREHENSIVE INCOME                                                                                                326,267
                                                     ---------     ---------        ---------           ---------      -----------

SEPTEMBER 30, 2003                                   $321,201      $462,484         $715,227            $(66,245)      $1,432,667
                                                     =========     =========        =========           =========      ===========
</TABLE>

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




<PAGE>
<TABLE>
<CAPTION>


                                                          OHIO POWER COMPANY CONSOLIDATED
                                                            CONSOLIDATED BALANCE SHEETS
                                                                      ASSETS
                                                       September 30, 2003 and December 31, 2002
                                                                    (Unaudited)

                                                                                                  2003                     2002
                                                                                                  ----                     ----
                                                                                                          (in thousands)

            ELECTRIC UTILITY PLANT
----------------------------------------------
<C>                                                                                            <C>                      <C>
Production                                                                                     $4,013,884               $3,116,825
Transmission                                                                                      928,373                  905,829
Distribution                                                                                    1,146,589                1,114,600
General                                                                                           239,523                  260,153
Construction Work in Progress                                                                     136,462                  288,419
                                                                                              ------------              -----------
Total                                                                                           6,464,831                5,685,826
Accumulated Depreciation and Amortization                                                       2,548,845                2,566,828
                                                                                              ------------              -----------
TOTAL - NET                                                                                     3,915,986                3,118,998
                                                                                              ------------              -----------

Other Property and Investments                                                                     52,907                   61,686
Long-term Risk Management Assets                                                                   62,885                  103,230

               CURRENT ASSETS
----------------------------------------------
Cash and Cash Equivalents                                                                           6,713                    5,285
Advances to Affiliates                                                                            142,894                        -
Accounts Receivable:
   Customers                                                                                       78,341                   95,100
   Affiliated Companies                                                                            92,972                  124,244
   Miscellaneous                                                                                   21,381                   19,281
   Allowance for Uncollectible Accounts                                                              (887)                    (909)
Fuel                                                                                               81,926                   87,409
Materials and Supplies                                                                             86,347                   85,379
Risk Management Assets                                                                             49,332                   92,108
Prepayments and Other                                                                              26,198                   12,083
                                                                                              ------------              -----------
TOTAL                                                                                             585,217                  519,980
                                                                                              ------------              -----------

Regulatory Assets                                                                                 512,890                  568,641

Deferred Charges and Other Assets                                                                  49,571                   84,497

TOTAL                                                                                          $5,179,456               $4,457,032
                                                                                              ============              ===========
</TABLE>

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


<PAGE>
<TABLE>
<CAPTION>


                                                      OHIO POWER COMPANY CONSOLIDATED
                                                        CONSOLIDATED BALANCE SHEETS
                                                       CAPITALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                                  2003                    2002
                                                                                                  ----                    ----
                                                                                                         (in thousands)
               CAPITALIZATION
----------------------------------------------
<C>                                                                                           <C>                     <C>
Common Shareholder's Equity:
  Common Stock - No Par Value:
     Authorized - 40,000,000 Shares
     Outstanding - 27,952,473 Shares                                                            $321,201                $321,201
    Paid-in Capital                                                                              462,484                 462,483
    Accumulated Other Comprehensive Income (Loss)                                                (66,245)                (72,886)
    Retained Earnings                                                                            715,227                 522,316
                                                                                              -----------             -----------
Total Common Shareholder's Equity                                                              1,432,667               1,233,114
                                                                                              -----------             -----------
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                    16,645                  16,648
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption                           8,350                   8,850
  Long-term Debt:
     Nonaffiliated                                                                             1,819,176                 677,649
     Affiliated                                                                                       -                  240,000
                                                                                              -----------             -----------
Total Long-term Debt                                                                           1,819,176                 917,649
                                                                                              -----------             -----------
TOTAL CAPITALIZATION                                                                           3,276,838               2,176,261
                                                                                              -----------             -----------

Minority Interest                                                                                 16,918                       -
Other Noncurrent Liabilities                                                                     209,808                 227,689

            CURRENT LIABILITIES
----------------------------------------------
Long-term Debt Due Within One Year - Nonaffiliated                                               268,919                  89,665
Long-term Debt Due Within One Year - Affiliated                                                        -                  60,000
Short-term Debt - General                                                                         28,651                       -
Short-term Debt - Affiliates                                                                           -                 275,000
Advances from Affiliates                                                                               -                 129,979
Accounts Payable - General                                                                        97,323                 170,563
Accounts Payable - Affiliated Companies                                                           67,516                 145,718
Customer Deposits                                                                                 16,548                  12,969
Taxes Accrued                                                                                     94,096                 111,778
Interest Accrued                                                                                  33,661                  18,809
Obligations Under Capital Leases                                                                   9,509                  14,360
Risk Management Liabilities                                                                       27,332                  61,839
Other                                                                                             69,846                  80,608
                                                                                              -----------             -----------
TOTAL                                                                                            713,401               1,171,288
                                                                                              -----------             -----------

Deferred Income Taxes                                                                            886,015                 794,387
Deferred Investment Tax Credits                                                                   16,460                  18,748
Long-term Risk Management Liabilities                                                             34,016                  39,702
Deferred Credits                                                                                  26,000                  28,957
Commitments and Contingencies (Note 5)

TOTAL                                                                                         $5,179,456              $4,457,032
                                                                                              ===========             ===========
</TABLE>

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





<PAGE>
<TABLE>
<CAPTION>



                                                      OHIO POWER COMPANY CONSOLIDATED
                                                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                           For the Nine Months Ended September 30, 2003 and 2002
                                                                (Unaudited)

                                                                                                         2003                2002
                                                                                                         ----                ----
                                                                                                               (in thousands)

               OPERATING ACTIVITIES
----------------------------------------------
<C>                                                                                                    <C>                 <C>
Net Income                                                                                             $319,626            $199,657
Adjustments to Reconcile Net Income to Net Cash Flows
   From Operating Activities:
      Cumulative Effect of Accounting Changes                                                          (124,632)               -
      Depreciation and Amortization                                                                     189,140             185,941
      Deferred Income Taxes                                                                               4,139                  95
      Mark-to-Market of Risk Management Contracts                                                        40,283             (34,477)
Changes in Certain Assets and Liabilities:
      Accounts Receivable, Net                                                                           45,966              14,289
      Fuel, Materials and Supplies                                                                        4,515              10,333
      Accrued Utility Revenues                                                                           (8,167)             (2,677)
      Prepayments and Other                                                                              (9,030)            (11,330)
      Accounts Payable                                                                                 (215,012)             20,011
      Customer Deposits                                                                                   3,579               9,101
      Taxes Accrued                                                                                     (17,682)             37,370
      Interest Accrued                                                                                    9,516               1,870
      Deferred Property Taxes                                                                            46,491              45,275
Change in Other Assets                                                                                  (10,895)            (18,513)
Change in Other Liabilities                                                                             (45,355)            (10,807)
                                                                                                       ---------           ---------
Net Cash Flows From Operating Activities                                                                232,482             446,138
                                                                                                       ---------           ---------

              INVESTING ACTIVITIES
----------------------------------------------
Construction Expenditures                                                                              (163,864)           (224,257)
Proceeds from Sale of Property and Other                                                                  3,620               5,444
                                                                                                       ---------           ---------
Net Cash Flows Used For Investing Activities                                                           (160,244)           (218,813)
                                                                                                       ---------           ---------

              FINANCING ACTIVITIES
----------------------------------------------
Issuance of Long-term Debt                                                                              950,000                -
Capital Contribution from Parent                                                                        (17,910)               -
Change in Advances to/from Affiliates, Net                                                             (272,872)           (139,531)
Change in Short-term Debt                                                                                 2,039                -
Change in Short-term Debt - Affiliates                                                                 (275,000)            150,000
Retirement of Long-term Debt - Nonaffiliated                                                            (29,850)           (140,000)
Retirement of Long-term Debt - Affiliated                                                              (300,000)               -
Retirement of Cumulative Preferred Stock                                                                   (502)               -
Dividends Paid on Common Stock                                                                         (125,800)            (97,746)
Dividends Paid on Cumulative Preferred Stock                                                               (915)               (944)
                                                                                                       ---------           ---------
Net Cash Flows Used For Financing Activities                                                            (70,810)           (228,221)
                                                                                                       ---------           ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                                      1,428                (896)
Cash and Cash Equivalents at Beginning of Period                                                          5,285               8,848
                                                                                                       ---------           ---------
Cash and Cash Equivalents at End of Period                                                               $6,713              $7,952
                                                                                                       =========           =========

</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $57,517,000 and
$56,864,000 and for income taxes was $74,858,000 and $29,981,000 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
         MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
         --------------------------------------------------------

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


Net Income increased $6 million year-to-date but decreased $3 million for the
third quarter. The increase for the year was due mainly to higher retail base
revenue and wholesale margins, while for the quarter a rise in Operating
Expenses offset these increases. Significant fluctuations occurred in Revenues,
Fuel and Purchased Electricity due to certain ICR adjustments in 2002 and
changing natural gas prices; however, operating income was not significantly
affected due to the functioning of the fuel adjustment clause in Oklahoma.


Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Operating Income

Operating Income decreased $7 million primarily due to the following:

    o A $2 million reduction resulting from the absence of the reversal of a
      Provision for Rate Refund that was recorded in 2002.
    o Decreased transmission revenues of $2 million.
    o Increased Other Operation and Maintenance expenses of $5 million due in
      large part to increased tree trimming and postretirement benefits
      expenses.

The decrease in Operating Income was partially offset by:

    o Increased wholesale margins of $3 million due to an increase in our
      percentage of margins earned from system risk management activities.
    o Increased retail base revenue of $5 million due in large part to an
      increase in industrial revenues. The number of cooling degree-days
      decreased 2%.

Other Impacts on Earnings

Nonoperating Income increased $6 million primarily due to a gain on the
disposition of excess land.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended
------------------------------------------------------------------
September 30, 2002
------------------

Operating Income

Operating Income increased $6 million primarily due to:

    o Increased wholesale margins of $7 million due to an increase in our
      percentage of margins earned from system risk management activities.
    o Increased  retail base revenue of $5 million,  resulting  mainly from
      increased KWH sales of 3%. Cooling  degree-days  decreased 5% while
      heating degree-days increased 14%.
         .
The increase in Operating Income was partially offset by:

    o Increased Other Operation expense of $4 million due mainly to employee
      related expenses consisting largely of increased cost for postretirement
      benefits.
    o Increased Taxes Other Than Income Taxes of $2 million due primarily to
      increased property value assessments and franchise taxes.


Other Impacts on Earnings

Nonoperating Income increased $5 million primarily due to a gain on the
disposition of excess land.

Interest Charges increased $5 million 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 and secured debt from A1 to A3
The completion of this review was a culmination of ratings action started during
2002. In March 2003, S&P lowered AEP and our senior unsecured debt and first
mortgage bonds ratings from BBB+ to BBB.


Financing Activity

Long-term debt issuances and retirements during the first nine months of 2003
were:


  Issuances
  ---------

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

 Senior Unsecured Notes        $150            4.85            2010


  Retirements
  -----------

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

 First Mortgage Bonds         $  35            6.25            2003
 First Mortgage Bonds            65            7.25            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.

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.
<TABLE>
<CAPTION>

             Roll-Forward of MTM Risk Management Contract Net Assets
                      Nine Months Ended September 30, 2003
                                 (in thousands)

     Domestic Power

     <C>                                                                        <C>
     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)
                                                                                 9,564
                                                                               --------
     Total MTM Risk Management Contract Net
      Assets                                                                    13,329
     Net Non-Trading Related Derivative
      Contracts                                                                    605
                                                                               --------
     Net Fair Value of Risk Management and   Derivative
     Contracts September 30, 2003                                              $13,934
                                                                               ========
</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, 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 September 30, 2003

                                         Remainder                                                         After
                                           2003             2004        2005        2006        2007        2007        Total
                                        -----------        ------      ------      ------      ------      ------      -------
                                                                          (in thousands)
<C>                                          <C>          <C>          <C>         <C>           <C>       <C>         <C>
 Prices Provided by Other External
  Sources - OTC Broker Quotes (a)            $287         $3,203       $1,415      $1,241        $294          $-      $6,440
 Prices Based on Models and Other
  Valuation Methods (b)                       481          1,164          739         893         985       2,627       6,889
                                             -----        -------      -------     -------     -------     -------    --------

 Total                                       $768         $4,367       $2,154      $2,134      $1,279      $2,627     $13,329
                                             =====        =======      =======     =======     =======     =======    ========
</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). In accordance with GAAP, all amounts are presented net of
related income taxes.

                Total Other Comprehensive Income (Loss) Activity
                      Nine Months Ended September 30, 2003

                                                                  Domestic
                                                                   Power
                                                                  ---------
                                                               (in thousands)
              Accumulated OCI, December 31, 2002                     $(42)
              Changes in Fair Value (a)                               259
              Reclassifications from OCI to Net
               Income (b)                                             176
                                                                    ------
              Accumulated OCI Derivative Gain  (Loss)
              September 30, 2003                                    $ 393
                                                                    ======



     (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 $685 thousand gain.

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>

                        September 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>
           $363      $1,029       $474       $102                               $136        $415         $148     $30
</TABLE>
<PAGE>



<TABLE>
<CAPTION>
                                                          PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                                STATEMENTS OF INCOME
                                            For the Three and Nine Months Ended September 30, 2003 and 2002
                                                                    (Unaudited)

                                                                      Three Months Ended                    Nine Months Ended
                                                                      ------------------                    -----------------
                                                                    2003               2002               2003              2002
                                                                   -----              -----              -----             -----
                                                                                            (in thousands)
                OPERATING REVENUES
---------------------------------------------------
<C>                                                               <C>               <C>                 <C>               <C>
Electric Generation, Transmission and Distribution                $355,064          $236,724            $860,544          $535,784
Sales to AEP Affiliates                                              3,511            (6,626)             17,929             1,630
                                                                  ---------         ---------           ---------         ---------
TOTAL                                                              358,575           230,098             878,473           537,414
                                                                  ---------         ---------           ---------         ---------
                 OPERATING EXPENSES
---------------------------------------------------
Fuel for Electric Generation                                       177,162            58,410             415,731           150,279
Purchased Electricity for Resale                                    11,524           (15,250)             30,878            (7,230)
Purchased Electricity from AEP Affiliates                           24,132            38,320              94,515            67,238
Other Operation                                                     33,765            31,957              97,067            92,845
Maintenance                                                         12,763            10,024              34,523            36,079
Depreciation and Amortization                                       21,715            22,496              64,568            64,473
Taxes Other Than Income Taxes                                        9,526             9,278              27,611            25,209
Income Taxes                                                        24,461            24,153              28,192            29,200
                                                                  ---------         ---------           ---------         ---------
TOTAL                                                              315,048           179,388             793,085           458,093
                                                                  ---------         ---------           ---------         ---------

OPERATING INCOME                                                    43,527            50,710              85,388            79,321

Nonoperating Income                                                  6,691             1,022               7,413             2,351
Nonoperating Expense                                                   304                 2                 467               666
Nonoperating Income Tax Expense                                      1,488               922               1,133               681
Interest Charges                                                    10,336             9,806              34,493            29,351
                                                                  ---------         ---------           ---------         ---------
NET INCOME                                                          38,090            41,002              56,708            50,974

Preferred Stock Dividend Requirements                                   53                53                 159               159
                                                                  ---------         ---------           ---------         ---------
EARNINGS APPLICABLE TO  COMMON STOCK
                                                                   $38,037           $40,949             $56,549           $50,815
                                                                  =========         =========           =========         =========

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.
</TABLE>
<PAGE>


<TABLE>
<CAPTION>

                                                 PUBLIC SERVICE COMPANY OF OKLAHOMA
                                            STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
                                                        COMPREHENSIVE INCOME
                                                            (in thousands)
                                                              (Unaudited)


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

<C>                                         <C>            <C>              <C>                  <C>            <C>
JANUARY 1, 2002                             $157,230       $180,016         $142,994                   $-        $480,240

Common Stock Dividends                                                       (67,368)                            (67,368)
Preferred Stock Dividends                                                       (159)                               (159)
                                                                                                                ---------
                                                                                                                 412,713
                                                                                                                ---------
      COMPREHENSIVE INCOME
-------------------------------
Other Comprehensive Income,
 Net of Taxes:
  Unrealized Gain on Cash Flow Hedges                                                                  45             45
NET INCOME                                                                    50,974                              50,974
                                                                                                                ---------
TOTAL COMPREHENSIVE INCOME                                                                                        51,019
                                            ---------      ---------        ---------            ---------      ---------

SEPTEMBER 30, 2002                          $157,230       $180,016         $126,441                  $45       $463,732
                                            =========      =========        =========            =========      =========


JANUARY 1, 2003                             $157,230       $180,016         $116,474             $(54,473)      $399,247

Capital Contribution from Parent                             50,000                                               50,000
Common Stock Dividends                                                       (15,000)                            (15,000)
Preferred Stock Dividends                                                       (159)                               (159)
Distribution of Investment in AEMT, Inc.
 Preferred Shares to Parent                                                     (548)                               (548)
                                                                                                                ---------
TOTAL                                                                                                            433,540
                                                                                                                ---------


      COMPREHENSIVE INCOME
-------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
  Minimum Pension Liability                                                                           (59)           (59)
  Unrealized Gain on Cash Flow Hedges                                                                 435            435
NET INCOME                                                                    56,708                              56,708
                                                                                                                ---------
TOTAL COMPREHENSIVE INCOME                                                                                        57,084
                                            ---------      ---------        ---------            ---------      ---------

SEPTEMBER 30, 2003                          $157,230       $230,016         $157,475             $(54,097)      $490,624
                                            =========      =========        =========            =========      =========

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


<TABLE>
<CAPTION>

                                                 PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                           BALANCE SHEETS
                                                              ASSETS
                                            September 30, 2003 and December 31, 2002
                                                            (Unaudited)

                                                                                              2003                    2002
                                                                                             ------                  ------
                                                                                                      (in thousands)

                 ELECTRIC UTILITY PLANT
--------------------------------------------------------
<C>                                                                                          <C>                    <C>
Production                                                                                   $1,064,055             $1,040,520
Transmission                                                                                    447,286                432,846
Distribution                                                                                  1,012,605                990,947
General                                                                                         194,317                206,747
Construction Work in Progress                                                                    52,881                 88,444
                                                                                             -----------            -----------
TOTAL                                                                                         2,771,144              2,759,504
Accumulated Depreciation and Amortization                                                     1,253,819              1,239,855
                                                                                             -----------            -----------
TOTAL - NET                                                                                   1,517,325              1,519,649
                                                                                             -----------            -----------

Other Property and Investments                                                                    7,147                  5,383
Long-term Risk Management Assets                                                                 15,967                  4,481


                   CURRENT ASSETS
--------------------------------------------------------
Cash and Cash Equivalents                                                                        17,587                 16,774
Advances to Affiliates                                                                          103,453                      -
Accounts Receivable:
  Customers                                                                                      26,639                 31,687
  Affiliated Companies                                                                           25,160                 14,139
  Allowance for Uncollectible Accounts                                                              (47)                   (84)
Fuel Inventory                                                                                   18,551                 19,973
Materials and Supplies                                                                           37,444                 37,375
Under-recovered Fuel Costs                                                                       43,608                 76,470
Risk Management Assets                                                                           12,772                  3,841
Prepayments and Other                                                                             3,633                  2,735
                                                                                             -----------            -----------
TOTAL                                                                                           288,800                202,910
                                                                                             ----------             -----------

Regulatory Assets                                                                                25,838                 26,150
Deferred Charges                                                                                 29,184                 18,117

TOTAL ASSETS                                                                                 $1,884,261             $1,776,690
                                                                                             ===========            ===========


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


<TABLE>
<CAPTION>

                                                     PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                               BALANCE SHEETS
                                                       CAPITALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                                  2003                  2002
                                                                                                 ------                ------
                                                                                                         (in thousands)
                          CAPITALIZATION
---------------------------------------------------------------
<C>                                                                                            <C>                    <C>
Common Shareholder's Equity:
  Common Stock - $15 Par Value:
    Authorized Shares: 11,000,000
    Issued Shares: 10,482,000
    Outstanding Shares: 9,013,000                                                                $157,230               $157,230
    Paid-in Capital                                                                               230,016                180,016
    Accumulated Other Comprehensive Income (Loss)                                                 (54,097)               (54,473)
    Retained Earnings                                                                             157,475                116,474
                                                                                               -----------            -----------
Total Common Shareholder's Equity                                                                 490,624                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
Long-term Debt                                                                                    672,691                445,437
                                                                                               -----------            -----------
TOTAL                                                                                           1,168,582                924,951
                                                                                               -----------            -----------

Other Noncurrent Liabilities                                                                       55,906                 54,761

                     CURRENT LIABILITIES
----------------------------------------------------------------
Long-term Debt Due Within One Year                                                                      -                100,000
Advances from Affiliates                                                                                -                 86,105
Accounts Payable:
 General                                                                                           52,350                 61,169
 Affiliated Companies                                                                              96,358                 78,076
Customer Deposits                                                                                  25,172                 21,789
Taxes Accrued                                                                                      19,196                  6,854
Interest Accrued                                                                                    7,648                  6,979
Risk Management Liabilities                                                                         7,873                  3,260
Other                                                                                              20,484                 24,957
                                                                                               -----------            -----------
TOTAL                                                                                             229,081                389,189
                                                                                               -----------            -----------

Deferred Income Taxes                                                                             350,295                341,396
Deferred Investment Tax Credits                                                                    30,858                 32,201
Regulatory Liabilities and Deferred Credits                                                        42,607                 32,611
Long-Term Risk Management Liabilities                                                               6,932                  1,581
Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                           $1,884,261             $1,776,690
                                                                                               ===========            ===========
See Notes to Respective Financial Statements beginning on page L-1.
</TABLE>
<PAGE>


<TABLE>
<CAPTION>
                                                        PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                            STATEMENTS OF CASH FLOWS
                                                For the Nine Months Ended September 30, 2003 and 2002
                                                                   (Unaudited)

                                                                                        2003                   2002
                                                                                       ------                 ------
                                                                                              (in thousands)
                      OPERATING ACTIVITIES
-----------------------------------------------------
<C>                                                                                   <C>                    <C>
Net Income                                                                             $56,708                $50,974
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Depreciation and Amortization                                                        64,568                 64,473
   Deferred Income Taxes                                                                 6,536                 33,841
   Deferred Investment Tax Credits                                                      (1,343)                (1,343)
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                             (6,010)               (27,994)
   Fuel, Materials and Supplies                                                          1,353                    426
   Accounts Payable                                                                      9,463                 35,739
   Taxes Accrued                                                                        12,342                 11,124
   Fuel Recovery                                                                        32,862               (108,565)
   Deferred Property Taxes                                                              (8,239)                (8,092)
Changes in Other Assets                                                                 (6,165)                  (103)
Changes in Other Liabilities                                                                54                (31,825)
                                                                                      ---------              ---------
Net Cash Flows From Operating Activities                                               162,129                 18,655
                                                                                      ---------              ---------

                      INVESTING ACTIVITIES
-----------------------------------------------------
Construction Expenditures                                                              (59,263)               (51,629)
Proceeds from Sale of Property                                                           2,664                    963
                                                                                      ---------              ---------
Net Cash Flows Used For Investing Activities                                           (56,599)               (50,666)
                                                                                      ---------              ---------

                      FINANCING ACTIVITIES
-----------------------------------------------------
Capital Contributions from Parent                                                       50,000                      -
Issuance of Long-term Debt                                                             150,000                      -
Change in Advances to/from Affiliates, Net                                            (189,558)               105,551
Retirement of Long-term Debt                                                          (100,000)                     -
Dividends Paid on Common Stock                                                         (15,000)               (67,368)
Dividends Paid on Cumulative Preferred Stock                                              (159)                  (159)
                                                                                      ---------              ---------
Net Cash Flows From (Used For) Financing Activities                                   (104,717)                38,024
                                                                                      ---------              ---------

Net Increase in Cash and Cash Equivalents                                                  813                  6,013
Cash and Cash Equivalents at Beginning of Period                                        16,774                  5,795
                                                                                      ---------              ---------
Cash and Cash Equivalents at End of Period                                             $17,587                $11,808
                                                                                      =========              =========

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $31,572,000 and
$24,853,000 and for income taxes was $33,658,000 and $2,962,000 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.
</TABLE>
<PAGE>


                SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                 ----------------------------------------------

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

Net Income for the first nine months of 2003 increased $10 million due to the
adoption of SFAS 143, which resulted in a Cumulative Effect of Accounting
Changes of $9 million in the first quarter of 2003. Net Income for the third
quarter decreased $4 million due to decreased margins and increased Interest
Charges. Significant fluctuations occurred in revenues, fuel and purchased power
due to certain ICR adjustments in 2002 and changing natural gas prices; however,
income is generally not affected due to the functioning of fuel adjustment
clauses in the retail jurisdictions.

Third Quarter 2003 Compared to Third Quarter 2002
-------------------------------------------------

Operating Income

Operating Income decreased by $1 million primarily due to:

         o A $2 million decrease in retail base revenues in large part due to
           a 9% decline in cooling-degree days.
         o A decline in risk management activities of $5 million.
         o A 19% increase in fuel expense resulting from a higher per unit cost
           of fuel, mostly natural gas, offset partially by reduced purchased
           power expense.
         o An increase of $1 million from Taxes Other Than Income Taxes due
           in large part to increased property taxes resulting from revised
           tax valuations.
         o A $3 million increase in Other Operation expense primarily due to
           increased deferred fuel expense.

The decrease in Operating Income was partially offset by:

         o An increase in retained margins from off-system sales of $6 million
           due to larger volumes.
         o A decrease in Maintenance expense of $1 million due mainly to
           reduced scheduled power plant maintenance.
         o A decrease of $1 million in Income Taxes due to a decrease in
           pre-tax operating book income.

Other Impacts on Earnings

Interest Charges increased $2 million primarily due to higher overall levels of
outstanding debt.

Minority Interest expense of $1 million is a result of consolidating Sabine
Mining Company during the third quarter of 2003, due to the implementation of
FIN 46. See Notes 2 and 6 for additional discussion.

Nine Months Ended September 30, 2003 Compared to Nine Months
------------------------------------------------------------
Ended September 30, 2002
------------------------

Operating Income

Operating Income increased by $6 million primarily due to:

         o An increase in retained margins from off-system sales of $11 million
           due to larger volumes.
         o An increase in retail base revenues of $6 million due to an
           increased number of customers and their average usage, offset in
           part by milder weather. Cooling degree-days declined 8% while
           heating degree-days increased 2%.
         o A $7 million increase in transmission revenues.
         o An increase in risk management activities of $4 million.
         o A decrease in Other Operation expense of $6 million primarily due
           to reduced transmission expense of $4 million.
         o A $2 million decrease in Maintenance expense due to reduced
           scheduled power plant maintenance and reduced tree trimming expense.

The increase in Operating Income was partially offset by:

         o A $7 million decrease in wholesale base margins partly due to
           decreased demand from wholesale customers.
         o A decrease in capacity revenues of $4 million, due to the
           elimination of the requirement under the Texas Restructuring
           legislation to sell capacity since they did not transition to
           competition.
         o An  increase in fuel expense of 17% due to a higher per unit cost of
           fuel, mostly natural gas, offset partially by reduced purchased
           power expense.
         o A $3 million  increase in Taxes Other Than Income Taxes due mainly
           to increased  property taxes  resulting from revised tax valuations.
         o An increase in Income Taxes of $2 million due to an increase in
           pre-tax operating book income and a change in certain book versus
           tax differences accounted for on a flow-through basis.

Other Impacts on Earnings

Interest Charges increased $5 million primarily due to higher overall levels of
outstanding debt.

Minority Interest expense of $1 million is a result of consolidating Sabine
Mining Company during the third quarter of 2003, due to the implementation of
FIN 46. See Notes 2 and 6 for additional discussion.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to the one-time, after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Note 2).

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

Credit Ratings

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

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

         First Mortgage Bonds               A3            BBB         A
         Senior Unsecured Debt              Baa1          BBB         A-

  In February 2003, Moody's Investors Service (Moody's) completed their review
  of AEP and its rated subsidiaries. The results of that review included a
  downgrade of our rating for unsecured debt from A2 to Baa1 and secured debt
  from A1 to A3. The completion of this review was a culmination of ratings
  action started during 2002. In March 2003, S&P lowered AEP and our senior
  unsecured debt and first mortgage bonds ratings from BBB+ to BBB.

Cash Flow

Cash flows for the nine months ended September 30, 2003 and 2002 were as
follows:
<TABLE>
<CAPTION>
                                                                               2003                  2002
                                                                               ------                ------
                                                                                      (in thousands)
           <C>                                                               <C>                 <C>
           Cash and cash equivalents at beginning of period                    $2,069              $5,415
           Cash flows from (used for):
             Operating activities                                             207,874             195,639
             Investing activities                                             (77,403)            (72,809)
             Financing activities                                            (115,951)           (122,541)
                                                                             ---------           ---------
           Net increase in cash and cash equivalents                           14,520                 289
                                                                             ---------           ---------
           Cash and cash equivalents at end of period                         $16,589              $5,704
                                                                             =========           =========
</TABLE>

Operating Activities

Cash flows from operating activities increased $12 million in the first nine
months of 2003 compared to the first nine months of 2002 primarily due to a
change in under-recovery of fuel costs due to higher natural gas prices in 2003
and a build-up of fuel inventory during 2002.

Investing Activities

Cash spent on investing activities increased $5 million in comparison to the
prior year. In 2003, $68 million of construction expenditures were related to
projects for improved transmission and distribution service reliability.

Financing Activities

Cash flows used for financing activities in the first nine months of 2003 were
comparable to the first nine months 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, one of our mining subsidiaries issued $44 million of notes due in 2011
at a coupon of 4.47%. The loan will be used primarily to reduce a note to us
with an interest rate of 8.06%.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2003
were:

  Issuances
  ---------
<TABLE>
<CAPTION>
                                                      Principal         Interest        Due
                   Type of Debt                        Amount             Rate          Date
                   ------------                       ---------         --------        -----
                                                    (in millions)         (%)

             <C>                                          <C>             <C>           <C>
             Senior Unsecured Notes                       $100            5.375         2015
             Secured Note of Subsidiary                     44            4.47          2011



</TABLE>

<TABLE>
<CAPTION>

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

             <C>                                          <C>           <C>             <C>
             First Mortgage Bonds                         $55             6.625         2003
             Secured Note of Subsidiary                     2             4.47          2011
             Notes Payable                                  1           Variable        2008
</TABLE>


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 combustion control
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, these costs would adversely affect future results of
operations, cash flows and possibly financial condition. See Note 5 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
                            Nine Months Ended September 30, 2003
                                       (in thousands)
<TABLE>
<CAPTION>

        Domestic Power
       ----------------

        <C>                                                            <C>
        Beginning Balance December 31, 2002                             $4,050
        (Gain) Loss from Contracts Realized/Settled
         During the Period (a)                                            (354)
        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)                                                   4,161
        Changes in Fair Value of Risk Management
         Contracts Allocated to Regulated Jurisdictions (e)              7,690
                                                                       --------
        Total MTM Risk Management Contract Net
         Assets                                                         15,698
        Net Non-Trading Related Derivative Contracts                      (531)
                                                                       --------
        Net Fair Value of Risk Management and Derivative
         Contracts September 30, 2003                                  $15,167
                                                                       ========
</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,
             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 September 30, 2003


                                               Remainder                                                        After
                                                 2003           2004         2005         2006        2007      2007        Total
                                               ----------      ------       ------       -----       ------    ------       -----
                                                                                  (in thousands)
<C>                                               <C>          <C>          <C>          <C>         <C>       <C>         <C>
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                  $337         $3,773       $1,667       $1,461        $346        $-       $7,584
Prices Based on Models and Other
 Valuation Methods (b)                             567          1,371          870        1,052       1,160     3,094        8,114
                                                  -----        -------      -------      -------     -------   -------     --------

Total                                             $904         $5,144       $2,537       $2,513      $1,506    $3,094      $15,698
                                                  =====        =======      =======      =======     =======   =======     ========
</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). In accordance with GAAP, all amounts are presented net of
related income taxes.

                Total Other Comprehensive Income (Loss) Activity
                      Nine Months Ended September 30, 2003

                                                        Domestic
                                                          Power
                                                       ----------
                                                      (in thousands)
       Accumulated OCI, December 31, 2002                  $(48)
       Changes in Fair Value (a)                            303
       Reclassifications from OCI to Net
        Income (b)                                          207
                                                           -----
       Accumulated OCI Derivative Gain  (Loss)
       September 30, 2003                                  $462
                                                           =====

         (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 $807 thousand gain.

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>

                        September 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>
            $427       $1,212       $558        $121                      $155       $474         $170      $34

</TABLE>
<PAGE>


<TABLE>
<CAPTION>
                                                  SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                         CONSOLIDATED STATEMENTS OF INCOME
                                           For the Three and Nine Months Ended September 30, 2003 and 2002
                                                                  (Unaudited)

                                                                     Three Months Ended                     Nine Months Ended
                                                                     ------------------                     -----------------
                                                                   2003              2002                 2003             2002
                                                                  ------            ------               ------           ------
                                                                                          (in thousands)
               OPERATING REVENUES
---------------------------------------------
<C>                                                              <C>                <C>                 <C>               <C>
Electric Generation, Transmission and Distribution               $347,672           $346,519            $835,193          $794,668
Sales to AEP Affiliates                                            13,950             15,904              63,013            53,088
                                                                 ---------          ---------           ---------         ---------
TOTAL                                                             361,622            362,423             898,206           847,756
                                                                 ---------          ---------           ---------         ---------

               OPERATING EXPENSES
---------------------------------------------
Fuel for Electric Generation                                      145,201            122,446             358,917           306,536
Purchased Electricity for Resale                                    6,567             29,820              29,499            40,290
Purchased Electricity from AEP Affiliates                          10,055             10,257              35,706            27,817
Other Operation                                                    53,743             51,005             131,256           137,288
Maintenance                                                        15,959             16,767              47,707            49,547
Depreciation and Amortization                                      30,381             31,764              89,284            92,437
Taxes Other Than Income Taxes                                      16,517             15,259              45,558            42,205
Income Taxes                                                       23,970             24,851              39,418            36,925
                                                                 ---------          ---------           ---------         ---------
TOTAL                                                             302,393            302,169             777,345           733,045
                                                                 ---------          ---------           ---------         ---------

OPERATING INCOME                                                   59,229             60,254             120,861           114,711

Nonoperating Income                                                 1,364              1,203               2,711             1,618
Nonoperating Expenses                                                 577                344               1,453             1,298
Nonoperating Income Tax Expense (Credit)                               18                176                 (37)               67
Interest Charges                                                   16,981             15,143              48,058            42,856
Minority Interest                                                    (836)                 -                (836)                -
                                                                 ---------          ---------           ---------         ---------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES              42,181             45,794              73,262            72,108
Cumulative Effect of Accounting Changes (Net of Tax)                    -                  -               8,517                 -
                                                                 ---------          ---------           ---------         ---------
NET INCOME                                                         42,181             45,794              81,779            72,108

Preferred Stock Dividend Requirements                                  57                 57                 172               172
                                                                 ---------          ---------           ---------         ---------

EARNINGS APPLICABLE TO COMMON STOCK                               $42,124            $45,737             $81,607           $71,936
                                                                 =========          =========           =========         =========


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.
</TABLE>
<PAGE>


<TABLE>
<CAPTION>

                                              SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                          CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
                                                       COMPREHENSIVE INCOME (LOSS)
                                                             (in thousands)
                                                               (Unaudited)


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


<C>                                              <C>            <C>            <C>                  <C>              <C>
JANUARY 1, 2002                                  $135,660       $245,003       $308,915                   $-         $689,578

Common Stock Dividends                                                          (56,889)                              (56,889)
Preferred Stock Dividends                                                          (172)                                 (172)
                                                                                                                     ---------
TOTAL                                                                                                                 632,517
                                                                                                                     ---------

           COMPREHENSIVE INCOME
-----------------------------------------
Other Comprehensive Income, Net of Taxes:
 Unrealized Gain on Cash Flow Power Hedges                                                                50               50
NET INCOME                                                                       72,108                                72,108
                                                                                                                     ---------
TOTAL COMPREHENSIVE INCOME                                                                                             72,158
                                                 ---------      ---------      ---------            ---------        ---------

SEPTEMBER 30, 2002                               $135,660       $245,003       $323,962                  $50         $704,675
                                                 =========      =========      =========            =========        =========


JANUARY 1, 2003                                  $135,660       $245,003       $334,789             $(53,683)        $661,769

Common Stock Dividends                                                          (54,596)                              (54,596)
Preferred Stock Dividends                                                          (172)                                 (172)
                                                                                                                     ---------
                                                                                                                      607,001
                                                                                                                     ---------
           COMPREHENSIVE INCOME
-----------------------------------------
Other Comprehensive Income, Net of Taxes:
  Unrealized Gain on Cash Flow Hedges                                                                    510              510
NET INCOME                                                                       81,779                                81,779
                                                                                                                     ---------
TOTAL COMPREHENSIVE INCOME                                                                                             82,289
                                                 ---------      ---------      ---------            ---------        ---------

SEPTEMBER 30, 2003                               $135,660       $245,003       $361,800             $(53,173)        $689,290
                                                 =========      =========      =========            =========        =========

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


<TABLE>
<CAPTION>
                                               SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                          CONSOLIDATED BALANCE SHEETS
                                                                   ASSETS
                                                   September 30, 2003 and December 31, 2002
                                                                 (Unaudited)

                                                                                                   2003                  2002
                                                                                                  ------                ------
                                                                                                         (in thousands)

                 ELECTRIC UTILITY PLANT
-------------------------------------------------------
<C>                                                                                            <C>                    <C>
Production                                                                                     $1,651,234             $1,503,722
Transmission                                                                                      609,775                575,003
Distribution                                                                                    1,071,355              1,063,564
General                                                                                           409,012                378,130
Construction Work in Progress                                                                      54,797                 75,755
                                                                                               -----------            -----------
TOTAL                                                                                           3,796,173              3,596,174
Accumulated Depreciation and Amortization                                                       1,852,603              1,697,338
                                                                                               -----------            -----------
TOTAL - NET                                                                                     1,943,570              1,898,836
                                                                                               -----------            -----------

Other Property and Investments                                                                      6,516                  5,978
Long-term Risk Management Assets                                                                   18,804                  5,119

                         CURRENT ASSETS
-------------------------------------------------------
Cash and Cash Equivalents                                                                          16,589                  2,069
Advances to Affiliates                                                                            123,790                      -
Accounts Receivable:
  Customers                                                                                        43,782                 62,359
  Affiliated Companies                                                                             49,204                 19,253
  Allowance for Uncollectible Accounts                                                             (2,140)                (2,128)
Fuel Inventory                                                                                     57,499                 61,741
Materials and Supplies                                                                             34,227                 33,539
Under-recovered Fuel Costs                                                                              -                  2,865
Risk Management Assets                                                                             15,041                  4,388
Prepayments and Other                                                                              19,978                 17,851
                                                                                               -----------            -----------
TOTAL                                                                                             357,970                201,937
                                                                                               -----------            -----------

Regulatory Assets                                                                                  52,715                 49,233
Deferred Charges                                                                                   70,183                 47,572

TOTAL ASSETS                                                                                   $2,449,758             $2,208,675
                                                                                               ===========            ===========
See Notes to Respective Financial Statements beginning on page L-1.
</TABLE>
<PAGE>


<TABLE>
<CAPTION>
                                              SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                        CONSOLIDATED BALANCE SHEETS
                                                       CAPITALIZATION AND LIABILITIES
                                                  September 30, 2003 and December 31, 2002
                                                                (Unaudited)

                                                                                  2003                 2002
                                                                                 ------               ------
                                                                                        (in thousands)

                        CAPITALIZATION
------------------------------------------------------------
<C>                                                                           <C>                  <C>
Common Shareholder's Equity:
  Common Stock - $18 Par Value:
     Authorized - 7,600,000 Shares
     Outstanding - 7,536,640 Shares                                             $135,660             $135,660
     Paid-in Capital                                                             245,003              245,003
     Accumulated Other Comprehensive Income (Loss)                               (53,173)             (53,683)
     Retained Earnings                                                           361,800              334,789
                                                                              -----------          -----------
Total Common Shareholder's Equity                                                689,290              661,769
  Cumulative Preferred Stock Not Subject to Mandatory Redemption                   4,700                4,701
  SWEPCo - Obligated, Mandatorily Redeemable Preferred Securities of
    Subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo           -              110,000
Long-term Debt                                                                   833,055              637,853
                                                                              -----------          -----------
TOTAL                                                                          1,527,045            1,414,323
                                                                              -----------          -----------

Minority Interest                                                                  1,651                    -
Other Noncurrent Liabilities                                                     111,107               78,494

                     CURRENT LIABILITIES
------------------------------------------------------------
Long-term Debt Due Within One Year                                                95,424               55,595
Advances from Affiliates, Net                                                          -               23,239
Accounts Payable - General                                                        49,352               62,139
Accounts Payable - Affiliated Companies                                           56,345               58,773
Customer Deposits                                                                 23,659               20,110
Taxes Accrued                                                                     62,641               19,081
Interest Accrued                                                                  15,308               17,051
Risk Management Liabilities                                                        9,876                3,724
Over-recovered Fuel                                                                  611               17,226
Other                                                                             45,661               34,565
                                                                              -----------          -----------
TOTAL                                                                            358,877              311,503
                                                                              -----------          -----------

Deferred Income Taxes                                                            352,601              341,064
Deferred Investments Tax Credits                                                  40,945               44,190
Regulatory Liabilities and Deferred Credits                                       48,730               17,295
Long-term Risk Management Liabilities                                              8,802                1,806
Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                          $2,449,758           $2,208,675
                                                                              ===========          ===========
See Notes to Respective Financial Statements beginning on page L-1.
</TABLE>
<PAGE>

<TABLE>
<CAPTION>
                                           SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                CONSOLIDATED STATEMENTS OF CASH FLOWS
                                         For the Nine Months Ended September 30, 2003 and 2002
                                                             (Unaudited)

                                                                                      2003               2002
                                                                                     ------              ------
                                                                                          (in thousands)
                         OPERATING ACTIVITIES
--------------------------------------------------------------
<C>                                                                                <C>                <C>
Net Income                                                                          $81,779             $72,108
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
    Depreciation and Amortization                                                    89,284              92,437
    Deferred Income Taxes                                                               421             (15,296)
    Deferred Investment Tax Credits                                                  (3,245)             (3,393)
    Cumulative Effect of Accounting Changes                                          (8,517)                  -
    Mark-to-Market of Risk Management Contracts                                     (11,497)             (4,534)
Changes in Certain Assets and Liabilities:
    Accounts Receivable, Net                                                         (8,862)            (10,293)
    Fuel, Materials and Supplies                                                     10,095              (6,596)
    Accounts Payable                                                                (18,773)              7,280
    Taxes Accrued                                                                    42,396              56,866
    Fuel Recovery                                                                   (13,750)             24,660
    Deferred Property Taxes                                                          (9,315)             (8,772)
Change in Other Assets                                                               (3,088)            (24,717)
Change in Other Liabilities                                                          60,946              15,889
                                                                                   ---------           ---------
Net Cash Flows From Operating Activities                                            207,874             195,639
                                                                                   ---------           ---------

                         INVESTING ACTIVITIES
--------------------------------------------------------------
Construction Expenditures                                                           (86,488)            (73,483)
Proceeds from Sale of Assets and Other                                                9,085                 674
                                                                                   ---------           ---------
Net Cash Flows Used For Investing Activities                                        (77,403)            (72,809)
                                                                                   ---------           ---------

                         FINANCING ACTIVITIES
--------------------------------------------------------------
Issuance of Long-term Debt                                                          144,324             198,614
Retirement of Long-term Debt                                                        (58,478)           (150,450)
Change in Advances to/from Affiliates, Net                                         (147,029)           (113,644)
Dividends Paid on Common Stock                                                      (54,596)            (56,889)
Dividends Paid on Cumulative Preferred Stock                                           (172)               (172)
                                                                                   ---------           ---------
Net Cash Flows Used For Financing Activities                                       (115,951)           (122,541)
                                                                                   ---------           ---------

Net Increase in Cash and Cash Equivalents                                            14,520                 289
Cash and Cash Equivalents at Beginning of Period                                      2,069               5,415
                                                                                   ---------           ---------
Cash and Cash Equivalents at End of Period                                          $16,589              $5,704
                                                                                   =========           =========

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $45,211,000 and
$34,860,000 and for income taxes was $26,166,000 and $24,102,000 in 2003 and
2002, respectively.

See Notes to Respective Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
                    NOTES TO RESPECTIVE FINANCIAL STATEMENTS
                    ----------------------------------------
                               SEPTEMBER 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:
<TABLE>
<CAPTION>


<C>             <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 and
                 Cumulative Effect of
                 Accounting Changes

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

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

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

6.              Guarantees                     AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

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

8.              Leases                         OPCo

9.              Financing and Related          AEGCo, 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 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 AND CUMULATIVE EFFECT OF ACCOUNTING
        -----------------------------------------------------------------
          CHANGES
          -------

        FIN 46 "Consolidation of Variable Interest Entities"

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

        On July 1, 2003, we deconsolidated the trusts which hold mandatorily
        redeemable trust preferred securities. Therefore, $321 million ($75
        million PSO, $110 million SWEPCo and $136 million TCC), previously
        reported as Certain Subsidiary Obligated, Mandatorily Redeemable,
        Preferred Securities of Subsidiary Trusts Holding Solely Junior
        Subordinated Debentures of Such Subsidiaries, is now reported as a
        component of Long-term Debt.

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

        Effective July 1, 2003, OPCo consolidated JMG Funding, LP (JMG). Upon
        consolidation, OPCo recorded the assets and liabilities of JMG ($469.6
        million). OPCo now records the depreciation, interest and other
        operating expenses of JMG and eliminates JMG's revenues against OPCo's
        operating lease expenses. There is no cumulative effect of an accounting
        change recorded as a result of our requirement to consolidate JMG, and
        there is no change in net income due to the consolidation of JMG. See
        Note 8 "Leases" for further disclosures.


        SFAS 143 "Accounting for Asset Retirement Obligations"

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

        We completed a review of our asset retirement obligations and concluded
        that we have related legal liabilities for nuclear decommissioning costs
        for I&M's Cook Plant and TCC's partial ownership in the South Texas
        Project, as well as liabilities for the retirement of certain ash ponds.
        Since we presently recover our nuclear decommissioning costs in our
        regulated cash flow and have existing balances recorded for such nuclear
        retirement obligations, we recognized the cumulative difference in the
        amount already provided through rates and the amount as measured by
        applying SFAS 143, as a regulatory asset or liability. Similarly, a
        regulatory asset was recorded for the cumulative effect of certain
        retirement costs for ash ponds related to our regulated operations. In
        the first quarter of 2003, AEP recorded an unfavorable cumulative effect
        for its 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 nine months ended September 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:
<TABLE>
<CAPTION>
                                     September 30, 2003          December 31, 2002
                                     ------------------          -----------------
                                                    (in millions)
          <C>                             <C>                         <C>
          AEGCo                           $ 28.6                      $ 28.0
          APCo                              90.0                        94.6
          CSPCo                             98.0                        96.0
          I&M                              260.9                       250.5
          KPCo                              22.0                        23.7
          OPCo                              97.6                        97.0
          PSO                              203.7                       202.6
          SWEPCo                           229.5                       219.5
          TCC                              101.7                        97.5
          TNC                               76.4                        75.0
</TABLE>

        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 nine months ended September 30, 2003:
<TABLE>
<CAPTION>

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

                                                         Reversal of
                                                           Cost of                             Reversal of
                                       Ash Ponds           Removal           Ash Ponds       Cost of  Removal
                                       ---------         ------------        ----------      -----------------
                 <C>                    <C>                <C>                <C>                <C>
                 AEGCo                  $   -              $   -               $  -               $  -
                 APCo                   (18.2)             146.5              (11.4)              91.7
                 CSPCo                   (7.8)              56.8               (4.7)              33.9
                 I&M                        -                  -                  -                  -
                 KPCo                       -                  -                  -                  -
                 OPCo                   (36.8)             250.4              (21.9)             149.3
                 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,                             Liabilities      September 30,
                                               2003              Accretion          Incurred             2003
                                            ----------          -----------       ------------      -------------
                                                                        (in millions)
             <C>                              <C>                  <C>                 <C>              <C>
             AEGCo (a)                         $1.1                  $-                 $-               $1.1
             APCo (a)                          20.1                 1.2                  -               21.3
             CSPCo (a)                          8.1                 0.5                  -                8.6
             I&M (b)                          516.1                27.6                  -              543.7
             OPCo (a)                          39.5                 2.3                  -               41.8
             SWEPCo (d)                           -                 0.2                8.1                8.3
             TCC (c)                          203.2                11.6                  -              214.8
</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 September 30, 2003) and nuclear
                  decommissioning costs for the Cook Plant ($542.6 million at
                  September 30, 2003).
              (c) Consists of asset retirement obligations related to nuclear
                  decommissioning costs for STP.
              (d) Consists of asset retirement obligations related to Sabine
                  Mining which is now being consolidated under FIN 46 (see FIN
                  46 "Consolidation of Variable Interest Entities" above).

        Accretion expense is included in Other Operation expense in the
        respective Income Statements of the individual subsidiary registrants.

        As of September 30, 2003 and December 31, 2002, the fair value of assets
        that are legally restricted for purposes of settling the nuclear
        decommissioning liabilities totaled $800 million ($685 million for I&M
        and $115 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 quarter ended
        September 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 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. 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
        also eliminated the recognition of physical inventories at fair value
        other than as provided by GAAP. We have implemented this standard for
        all physical inventory and non-derivative energy trading transactions
        occurring on or after October 25, 2002. For physical inventory and
        non-derivative energy trading transactions entered into prior to October
        25, 2002, we implemented this standard on January 1, 2003 and reported
        the effects of implementation as a cumulative effect of an accounting
        change.

        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)

          <C>                             <C>                    <C>                   <C>                   <C>
          APCo                            $128.3                 $ 80.3                $ (4.7)               $ (3.0)
          CSPCo                             49.0                   29.3                  (3.1)                 (2.0)
          I&M                                  -                      -                  (4.9)                 (3.2)
          KPCo                                 -                      -                  (1.7)                 (1.1)
          OPCo                             213.6                  127.3                  (4.2)                 (2.7)
          SWEPCo                            13.0                    8.4                   0.2                   0.1
          TCC                                  -                      -                   0.2                   0.1
          TNC                                4.7                    3.1                     -                     -
</TABLE>


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

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


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

        We implemented SFAS 150 effective July 1, 2003. SFAS 150 is the 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.

        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 SFAS 150,
        any measurement change for these liabilities is to be reported as the
        cumulative effect of a change in accounting principle.

        Beginning with the third quarter 2003 financial statements, $83 million
        ($11 million APCo, $63 million I&M and $9 million OPCo) of Cumulative
        Preferred Stock Subject to Mandatory Redemption is now presented as
        Liability for Cumulative Preferred Stock Subject to Mandatory Redemption
        within the Capitalization section of the balance sheet in order to
        identify it as a liability. Beginning July 1, 2003, dividends on these
        mandatorily redeemable preferred shares are now classified as Interest
        Charges on the statements of operations. In accordance with SFAS 150,
        dividends from prior periods remain classified as Preferred Stock
        Dividends.


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

        In November 2002, the FASB issued FIN 45 which clarifies the accounting
        to recognize a liability related to issuing a guarantee, as well as
        additional disclosures of guarantees. This 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 are effective
        on a prospective basis for guarantees issued or modified after December
        31, 2002. The disclosure requirements of FIN 45 are effective for
        financial statements of interim or annual periods ending after December
        15, 2002. See Note 6 for further disclosures.


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


        Fuel in SPP Area of Texas  - 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 PTB fuel factors offered by the 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 - 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 for under-recovered fuel costs.
        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 includes a
        recommendation 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 recommendations in the
        PFD. 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 two issues. 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. 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. TNC made a filing on July 15, 2003 addressing
        the remand issues. Intervenors and the PUCT Staff filed statements of
        position or testimony in August 2003 and TNC filed rebuttal testimony in
        September 2003. The intervenors recommended $14.3 million of
        disallowances for the two remanded issues. On September 9, 2003,
        portions of TNC's testimony which related to the requirements of the
        AEP/CSW merger settlement to share off-system sales margins were
        stricken by the ALJ. The ALJ ruled that the requirement to share
        off-system sales margins had been determined by the PUCT and that the
        scope of the remand was only to determine the off-system sales margin
        sharing methodology. 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
        thorough review of the evidence it is only reasonably possible that TNC
        will ultimately share margins after the end of the Texas fuel factor.
        Due to a provision established in the first quarter of 2003, the
        resolution of the fuel factor issue should have an immaterial impact on
        future results of operations, cash flows and financial condition.
        However, the ultimate decision could result in additional income
        reductions for these issues. It is presently expected that the ALJ's PFD
        and the PUCT's final decision regarding 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 to June 2000 and reflected
        the order in its financial statements. This final order was appealed to
        the Travis County District Court. In May 2003, the District Court upheld
        the PUCT's final order. That order is currently on appeal to the Third
        Court of Appeals.


        TCC Fuel Reconciliation  - Affecting  TCC

        In December 2002, TCC filed 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 TCC's 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. An ALJ report is expected in 2003 or the first quarter of
        2004.

        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. In July
        2003, the ALJ requested that additional information be provided in the
        TCC fuel reconciliation related to the impact of the TNC remand order on
        TCC. Management believes, based on advice of counsel, that it is only
        reasonably possible that it will ultimately be determined that TCC
        should share off-system sales margins after the end of the Texas fuel
        factor. However, an adverse ruling 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 4 "Customer Choice and Industry Restructuring."


        SWEPCo Texas 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. Any
        ruling by the PUCT preventing recovery of SWEPCo's fuel costs could have
        a material impact on future results of operations, cash flows and
        financial condition. Intervenor and PUCT Staff recommendations will be
        filed in November 2003 and hearings are scheduled for January 2004.


        ERCOT Price-to-Beat 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, and that the PUCT improperly shifted the burden of proof and the
        record lacked substantial evidence on the effect of loss of load due to
        retail competition on generation requirements. The Court upheld the
        initial PTB orders on all other issues. In the Mutual Energy CPL
        proceeding, the Court ruled that the PUCT improperly shifted the burden
        of proof and the record lacked substantial evidence on the effect of
        loss of load due to retail competition on generation requirements. The
        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 appealed the
        District Court decisions to the Third Court of Appeals 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 from the FERC of
        wholesale transmission rates determined in the UCOS proceeding. 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 including a nuclear
        decommissioning fund charge and a municipal franchise fee, a system
        benefit fund fee, a transition charge associated with securitization of
        regulatory assets and a credit for excess earnings. Certain rulings of
        the PUCT in the UCOS proceeding, including the initial determination of
        stranded costs, the requirement to refund TCC's excess earnings,
        regulatory treatment of nuclear insurance and distribution rates charged
        municipal customers, were appealed to the Travis County District Court
        by TCC and other parties to the proceeding. The District Court issued a
        decision on June 16, 2003, upholding the PUCT's UCOS order with one
        exception. The Court ruled that the refund of the 1999 through 2001
        excess earnings solely as a credit to non-bypassable transmission and
        distribution rates charged to REPs discriminates against residential and
        small commercial customers and is unlawful. The distribution rate credit
        began in January 2002. This decision could potentially affect the PTB
        rates charged by the AEP REP (Mutual Energy CPL) and could result in a
        refund to certain of its customers. Mutual Energy CPL was a subsidiary
        of AEP until December 23, 2002 when it was sold. Management estimates
        that the effect of 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 advice 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, Texas requested that TCC provide
        justification showing that its transmission and distribution rates
        should not be reduced. Other municipalities served by TCC passed similar
        rate review resolutions. In Texas, municipalities have original
        jurisdiction over rates of electric utilities within their municipal
        limits. Under Texas law, TCC 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 filed the requested support for its rates
        (test year ending June 30, 2003) with both the cities and the PUCT on
        November 3, 2003. TCC filed to decrease its wholesale transmission rates
        by $2 million or 2.5% and increase its retail energy delivery rates by
        $69 million or 19.2%. Management is unable to predict the ultimate
        effect of this proceeding on TCC's rates or its impact on TCC's results
        of operations, cash flows and financial condition.


        Louisiana Fuel Audit - Affecting SWEPCO

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


        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, but it 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 5.

        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 OCC filed an application requiring
        PSO to file all documents necessary for a general rate review before
        August 1, 2003 (revised to October 31, 2003). In October 2003, PSO filed
        the required data for this case and requested an increase of $36 million
        annually, which is an 8.7% increase over existing base rates. A
        procedural schedule has not been set for this case. Management is unable
        to predict the ultimate effect of this review on PSO's rates or its
        impact on PSO's results of operations, cash flows and financial
        condition.


        PSO Fuel and Purchased Power - Affecting PSO

        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 in 2002 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. In August 2003, the OCC Staff filed
        testimony recommending recovery of $42.4 million ($44 million less two
        audit adjustments) over three years. In September 2003, the OCC expanded
        the case to include a full prudence review of PSO's 2001 fuel and
        purchased power practices. If the OCC does not permit recovery of the
        $42.4 million or determines, as a result of the review, that material
        fuel and purchased power cost should not be recovered, there will be an
        adverse effect on PSO's results of operations, cash flows and possibly
        financial condition.


        Merger Mitigation Sales - Affecting PSO, SWEPCo, TCC and TNC

        As a condition of AEP/CSW merger approval at the FERC, the AEP West
        companies were required to mitigate market power concerns in SPP by
        divesting 300 MW of SPP capacity and selling 300 MW of SPP capacity at
        auction on an interim basis until the divestiture is completed. The
        margins from the interim sales were to be shared with customers in
        accordance with the existing margin sharing if they were positive on an
        annual basis and customers were to be held harmless if the margins on an
        annual basis were negative. Consequently, for proper accounting, the
        margins were deferred until year end.

        On September 1, 2003, AEP sold its share of the Eastex plant located in
        SPP. As a result of the sale, AEP satisfied the 300 MW FERC divestiture
        requirement in SPP. Based on the advice of counsel, management has
        concluded that it is no longer required to make the agreed upon 300 MW
        interim merger mitigation sale. The AEP West companies had $8.7 million
        of net merger mitigation sales losses deferred. Since these sales are no
        longer required, the final adjustment to the accrual occurred in
        September 2003. The amounts of revenues reversed were $8.6 million by
        PSO, $0.7 million by TCC and $1.2 million by TNC. SWEPCo recorded its
        gain of $1.8 million as revenues.


        Virginia Fuel Factor Filing - Affecting APCo

        APCo filed with the Virginia SCC to reduce its fuel factor effective
        August 1, 2003. The requested fuel rate reduction would be effective for
        17 months and is estimated to reduce revenues by $36 million during that
        17-month period. By order dated July 23, 2003, the Virginia SCC approved
        APCo's requested fuel factor reduction on an interim basis, subject to
        further investigation. No other parties to the proceeding have raised
        any issues with respect to APCo's request and the Virginia SCC Staff has
        filed testimony recommending that APCo's request be approved. This fuel
        factor adjustment will reduce cash flows without impacting results of
        operations as any over-recovery or under-recovery of fuel costs would be
        deferred as a regulatory liability or a regulatory asset. A hearing on
        this matter was held on November 5, 2003.


        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 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 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. At a hearing held in April 2003, the utilities asked FERC
        to void the long-term contracts. In June 2003, the FERC issued an order
        affirming the ALJ's decision and denying the utilities' complaint. The
        utilities requested a rehearing. In August 2003, the FERC granted the
        request for rehearing. Management is unable to predict the outcome of
        this proceeding or its impact on future results of operations and cash
        flows.


        RTO Formation/Integration Costs - Affecting APCo, CSPCo, I&M,
        KPCo, and OPCo

        With FERC approval, AEP East companies have been deferring costs
        incurred under FERC orders to form an RTO (the Alliance RTO) or join an
        existing RTO (PJM). In July 2003, the FERC issued an order approving our
        continued deferral of both our Alliance formation costs and our PJM
        integration costs including the deferral of a carrying charge. The AEP
        East companies have deferred approximately $24 million of RTO formation
        and integration costs and related carrying charges (APCo-$7 million,
        CSPCo-$3 million, I&M-$5 million, KPCo-$1 million, OPCo-$8 million)
        through September 30, 2003. As a result of the subsequent delay in the
        integration of AEP's East transmission system into PJM, FERC declined to
        rule, in its July order, on our request to transfer the deferrals to
        regulatory assets, and to maintain the deferrals until such time as the
        costs can be recovered from all users of AEP's East transmission system.
        The AEP East companies will apply for permission to transfer the
        deferred formation/integration costs to a regulatory asset prior to
        integration with PJM. In August 2003, the Virginia SCC filed a request
        for rehearing of the July order, arguing that FERC's action was an
        infringement on state jurisdiction, and that FERC should not have
        treated Alliance RTO startup costs in the same manner as PJM integration
        costs. On October 22, 2003, FERC denied the rehearing request.

        In 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 July 2003, the KPSC
        denied KPCo's request to join PJM based in part on a lack of evidence
        that it would benefit Kentucky retail customers. In August 2003, KPCo
        sought and was granted a rehearing allowing us to submit additional
        evidence. A hearing date has not been scheduled.

        In September 2003, the IURC issued an order approving I&M's transfer of
        functional control over its transmission facilities to PJM, subject to
        certain conditions included in the order. The IURC's order stated that
        AEP shall request and the IURC shall complete a review of Alliance
        formation costs ($2 million for I&M) before any deferral of the costs
        for future recovery. On September 30, 2003, AEP filed a petition for
        reconsideration of the IURC's order, asking the IURC to clarify that its
        discussion of the Alliance formation costs was not intended to cause an
        immediate write-off of the Indiana retail portion of these costs.

        In its July 2003 order, FERC indicated that it would review the deferred
        costs at the time they are transferred to a regulatory asset account and
        scheduled for amortization and recovery in the open access transmission
        tariff (OATT) to be charged by PJM. Management believes that the FERC
        will grant permission for the deferred RTO costs to be amortized and
        included in the OATT. Whether the amortized costs will be fully
        recoverable depends upon the state regulatory commissions' treatment of
        AEP East companies' portion of the OATT at the time they join PJM.
        Presently, retail rates are frozen or capped and cannot be increased for
        retail customers of CSPCo, I&M and OPCo. APCo's base rates are capped
        with no changes possible prior to January 1, 2004. AEP intends to file
        an application with FERC seeking permission to delay the amortization of
        the deferred RTO formation/integration costs until they are recoverable
        from all users of the transmission system including retail customers.
        Management is unable to predict the timing of when AEP will join PJM and
        if upon joining PJM whether FERC will grant a delay of recovery until
        the rate caps and freezes end. If AEP East companies do not obtain
        regulatory approval to join PJM, we are committed to reimburse PJM for
        certain project implementation costs (presently estimated at $23 million
        for the entire PJM integration project). Management intends to seek
        recovery of the deferred RTO formation/integration costs and project
        implementation cost reimbursements, if incurred. If the FERC ultimately
        decides not to approve a delay or the state commissions deny recovery,
        future results of operations and cash flows could be adversely affected.


        FERC Order on Regional Through and Out Rates - 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 (RTO Footprint). In
        October 2003, the FERC postponed the November 1, 2003 deadline to
        eliminate RTOR. 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 RTOR 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
        made a filing with the FERC supporting the justness and reasonableness
        of its rates in August 2003 and made a joint filing with unaffiliated
        utilities, on October 14, 2003, proposing a regional revenue replacement
        mechanism for the lost revenues, in the event that FERC eliminates AEP's
        ability to collect RTOR in the RTO Footprint. Also on October 14, 2003,
        FERC issued an order delaying the November 1, 2003 elimination of RTORs
        without setting a new date for such elimination. The AEP East companies
        received approximately $150 million of RTOR revenues from transactions
        delivering energy to customers in the RTO Footprint for the twelve
        months ended June 30, 2003. At this time, management is unable to
        predict the ultimate outcome of this investigation, or its impact on
        future results of operations, cash flows and financial condition.


        Indiana Fuel Order - Affecting I&M

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

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


        Michigan 2004 Fuel Recovery Plan - Affecting I&M

        The MPSC's December 16, 1999 order approved a Settlement Agreement
        regarding the extended outage of the Cook Plant and fixed I&M Power
        Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers
        rate areas through December 2003. In accordance with the settlement,
        PSCR Plan cases were not required to be filed through the 2003 plan
        year. For the 2004 plan year, I&M was required to file a PSCR Plan case
        with the MPSC by September 30, 2003. I&M filed its 2004 PSCR Plan with
        the MPSC on September 30, 2003 seeking new fuel and power supply
        recovery factors to be effective in 2004.

4.      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 occurred
            o  requiring the pricing of standard offer electric generation
               effective January 1, 2006 at the market price used by CSPCo and
               OPCo in their 1999 transition plan filings to estimate
               transition costs and
            o  imposing a $25,000 per company forfeiture for each day AEP
               fails to comply with its commitment to transfer control of
               transmission assets to an RTO

        Due to 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 currently unable to predict the timing of
        the AEP East companies' (including CSPCo and OPCo) 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 Market Development Period (MDP) during which
        retail customers can choose their electric power suppliers or receive
        Default Service at frozen generation rates from the incumbent utility.
        The MDP began on January 1, 2001 and is scheduled to terminate no later
        than December 31, 2005. The PUCO may terminate the MDP for one or more
        customer classes before that date if it determines either that effective
        competition exists in the incumbent utility's certified territory or
        that there is a twenty percent switching rate of the incumbent utility's
        load by customer class. Following the MDP, retail customers will receive
        distribution and transmission service from the incumbent utility whose
        distribution rates will be approved by the PUCO and whose transmission
        rates will be approved by the FERC. Retail customers will continue to
        have the right to choose their electric power suppliers or receive
        Default Service, which must be offered by the incumbent utility at
        market rates. 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 MDP.

        As provided in stipulation agreements approved by the PUCO, CSPCo and
        OPCo are deferring customer choice implementation costs that are in
        excess of $20 million per company. The agreements provide for the
        deferral of these costs as a regulatory asset until the company's next
        distribution base rate case. At September 30, 2003, CSPCo has incurred
        $31 million and deferred $11 million and OPCo has incurred $34 million
        and deferred $14 million of such costs. Recovery of these regulatory
        assets will be subject to PUCO review in each company's next Ohio filing
        for new distribution rates. Approved rates will not become effective
        prior to 2009 for CSPCo and 2008 for OPCo. Management believes that the
        customer choice implementation costs were prudently incurred and the
        deferred amounts should be recoverable in future rates. If the PUCO
        determines that any of the deferred costs are unrecoverable, it would
        have an adverse impact on future results of operations and cash flows.


        Texas Restructuring - Affecting SWEPCo, TCC and TNC

        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 and recovery of
        stranded plant costs as of December 31, 2001 including certain
        environmental costs incurred by May 1, 2003, final deferred fuel
        balance, net generation-related regulatory assets, unrefunded
        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 true-up issues.

        The Texas Legislation provides for an earnings test each year from 1999
        through 2001 and requires PUCT approval of the annual earnings test
        calculation. TCC, TNC and SWEPCo had appealed the PUCT's Final 2000
        Earnings Test Order to the Texas Court of Appeals. In August 2003, the
        Appeals Court reversed the PUCT order and the district court judgment
        affirming it and remanded the controversy back to the PUCT for
        proceedings consistent with the Appeals Court's decision. The PUCT
        requested rehearing of the Court of Appeal's decision. Our appeal of the
        same issue from the PUCT's 2001 Order is pending before the District
        Court. Since an expense and regulatory liability had been accrued in
        prior years in compliance with the PUCT Final Orders, the companies
        reversed a portion of their regulatory liability and credited
        amortization expense during the third quarter of 2003. Pre-tax amounts
        by company were $5.1 million for TCC, $2.6 million for TNC and $1.1
        million for SWEPCo.

        The Texas Legislation provides for the affiliated PTB REP to refund to
        its transmission and distribution (T&D) utility the excess of the PTB
        revenues over market prices (subject to certain conditions and a
        limitation of $150 per customer). This is the retail clawback. The
        retail clawback regulatory liability is to be included in the 2004
        true-up proceedings and netted against other true-up adjustments. If 40%
        of the load for the residential or small commercial classes is served by
        competitive REPs, the retail clawback is not applicable for that class
        of customer. In July 2003, TCC and TNC filed to notify the PUCT that
        competitive REPs serve over 40% of the load in the small commercial
        class. On August 21, 2003, the PUCT dismissed these filings and ruled
        that TCC and TNC should refile no sooner than September 22, 2003 in
        order to establish the required notice period. TCC and TNC refiled in
        late September 2003. In October 2003, the PUCT Staff recommended
        approval of TCC's application and denial of TNC's application. The PUCT
        Staff determined that only 39.9% of TNC's small commercial customers
        were served by competitive REPs as of the end of August 2003. If the
        PUCT denies TNC's application, TNC will likely meet the 40% threshold in
        September 2003 and refile its application. AEP had accrued a regulatory
        liability of approximately $9 million for the small commercial retail
        clawback on its REP's books. If the PUCT certifies that TCC and/or TNC
        have reached the 40% threshold, the regulatory liability would no longer
        be required for the small commercial class and could be reversed.

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

        In the fourth quarter of 2002, TCC decided to determine the market value
        of its generating assets through the sale of those assets for purposes
        of determining stranded costs for the 2004 true-up proceeding. In
        December 2002, TCC filed a plan of divestiture with the PUCT seeking
        approval of a sales process for all of its generating facilities. The
        amount of stranded costs under this market valuation methodology will be
        the amount by which the book value of TCC's generating assets, including
        regulatory assets and liabilities that were not securitized, exceeds the
        market value of the generation assets as measured by the net proceeds
        from the sale of the assets. It is anticipated that any such sale will
        result in significant stranded costs for purposes of TCC's 2004 true-up
        proceeding. 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 establish its market value for determining
        stranded plant 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 such 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 closing process for the plants sold is not expected to be
        completed before mid-2004, TCC requested that its 2004 true-up
        proceeding be scheduled after completion of the divestiture of its
        generating assets.

        In March 2003, the PUCT dismissed TCC's divestiture filing, determining
        that it was more appropriate to address allowable valuation methods for
        the nuclear asset in a rulemaking proceeding. The PUCT approved a rule,
        in May 2003, which allows the market value obtained by selling nuclear
        assets to be used in determining stranded costs. The PUCT dismissed
        TCC's request to certify its proposed divestiture plan; therefore its
        divestiture plan will be subject to a review in the 2004 true-up
        proceeding. 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 or 60 days after the completion of the sale of TCC's
        generation assets, if later.

        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. Actual market power prices
        received in the state mandated auctions will replace the PUCT's earlier
        estimates of those market prices for 2002 and 2003 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 cost instead of using the PUCT's ECOM model
        negative stranded cost estimate, 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 September 30, 2003, TCC recorded an additional $169
        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 negative ECOM estimate prohibited the
        recognition of the regulatory assets and revenues, as they can not be
        recovered unless there are stranded costs. However, in March 2003, the
        Texas Court of Appeals ruled that under the restructuring legislation,
        other 2004 true-up items including the wholesale capacity auction
        true-up regulatory asset, could be recovered regardless of the level of
        stranded plant costs.

        In July 2003, the PUCT Staff published their proposed filing package for
        the 2004 true-up proceeding. Within the filing package are instructions
        and sample schedules that demonstrate the calculation of the wholesale
        capacity auction true-up. That calculation differs from the methodology
        being employed by TCC. TCC filed comments on the proposed 2004 true-up
        filing package in September 2003 and took exception to the methodology
        employed by the PUCT Staff. A true-up filing package will probably be
        approved by the PUCT in the fourth quarter of 2003. If the PUCT Staff's
        methodology is approved, TCC's wholesale capacity auction true-up
        regulatory asset could require adjustment.

        In October 2003, a coalition of consumer groups (the Coalition of
        Ratepayers) including the Office of Public Utility Counsel, the State of
        Texas, Cities served by CPL and Texas Industrial Energy Consumers filed
        a petition with the PUCT requesting that the PUCT initiate a rulemaking
        to amend the PUCT's stranded cost true-up rule (True-up Rule). The
        Coalition of Ratepayers proposed to amend the True-up Rule to revise the
        calculation of the wholesale capacity auction true-up. If adopted, the
        Coalition of Ratepayers' proposal would substantially reduce or possibly
        eliminate the wholesale capacity auction true-up regulatory asset that
        TCC has accrued in 2002 and 2003. The PUCT requested that responses to
        the Coalition of Ratepayers' petition be filed by November 7, 2003. On
        November 5, 2003, the PUCT denied the Coalition of Ratepayers' petition.

        When the plant divestitures and the 2004 true-up proceeding are
        completed, TCC will file to recover PUCT-approved stranded costs and
        other true-up amounts that are in excess of current securitized amounts
        plus a carrying charge through a non-bypassable competition transition
        charge in rates of the regulated T&D utility. In addition, TCC may seek
        to securitize certain of the approved stranded plant costs and
        regulatory assets, not previously recovered through the non-bypassable
        transition charge. The annual costs of securitization are recovered
        through a non-bypassable rate surcharge collected by the T&D utility
        over the term of the securitization bonds.

        In the event 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 plant costs, wholesale
        capacity auction true-up regulatory assets, other restructuring true-up
        items and costs, it could have a material adverse effect on results of
        operations, cash flows and possibly financial condition.


        Arkansas Restructuring - Affecting SWEPCo

        In February 2003, Arkansas repealed customer choice legislation
        originally enacted in 1999. Consequently, SWEPCo's Arkansas operations
        reapplied SFAS 71 regulatory accounting, which had been discontinued in
        1999. The reapplication of SFAS 71 had an insignificant effect on
        results of operations and financial condition. As a result of reapplying
        SFAS 71, derivative contract gains/losses for transactions within AEP's
        traditional marketing area allocated to Arkansas will not affect income
        until settled. That is, such positions will be recorded on the balance
        sheet as either a regulatory asset or liability until realized.


        West Virginia Restructuring - Affecting APCo

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

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

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

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

        Reapplying SFAS 71 in WV had an insignificant effect on results of
        operations and financial condition. As a result, derivative contract
        gains/losses related to transactions within AEP's traditional marketing
        area allocated to WV will not affect income until settled. That is, such
        positions will be recorded on the balance sheet as either a regulatory
        asset or liability until realized. Positions outside AEP's traditional
        marketing area will continue to be marked-to-market.

5.      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 tubes were repaired and the
        unit returned to service in August 2003. TCC's share of the cost of
        repair for this outage was approximately $6 million. We had commitments
        to provide power to customers during the outage. Therefore, we were
        subject to fluctuations in the market prices of electricity and
        purchased replacement energy.

        In April 2003, both units of 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), AEPSC, APCo, CSPCo, I&M, and OPCo are involved in
        litigation regarding generating plant emissions under the Clean Air Act.
        The 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. The 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.

        On August 7, 2003, the District Court issued a decision following a
        liability trial in a case pending in the Southern District of Ohio
        against Ohio Edison Company, an unaffiliated utility. The District Court
        held that replacements of major boiler and turbine components that are
        infrequently performed at a single unit, that are performed with the
        assistance of outside contractors, that are accounted for as capital
        expenditures, and that require the unit to be taken out of service for a
        number of months are not "routine" maintenance, repair, and replacement.
        The District Court also held that a comparison of past actual emissions
        to projected future emissions must be performed prior to any non-routine
        physical change in order to evaluate whether an emissions increase will
        occur, and that increased hours of operation that are the result of
        eliminating forced outages due to the repairs must be included in that
        calculation. Based on these holdings, the District Court ruled that all
        of the challenged activities in that case were not routine, and that the
        changes resulted in significant net increases in emissions for certain
        pollutants. A remedy trial is scheduled for April 2004.

        Management believes that the Ohio Edison decision fails to properly
        evaluate and apply the applicable legal standards. The facts in the AEP
        case also vary widely from plant to plant. Further, the Ohio Edison
        decision is limited to liability issues, and provides no insight as to
        the remedies that might ultimately be ordered by the Court.

        On August 26, 2003, the District Court for the Middle District of South
        Carolina issued a decision on cross-motions for summary judgment prior
        to a liability trial in a case pending against Duke Energy Corporation,
        an unaffiliated utility. The District Court denied all the pending
        motions, but set forth the legal standards that will be applied at the
        trial in that case. The District Court determined that Federal EPA bears
        the burden of proof on the issue of whether a practice is "routine
        maintenance, repair, or replacement" and on whether or not a
        "significant net emissions increase" results from a physical change or
        change in the method of operation at a utility unit. However, the
        Federal EPA must consider whether a practice is "routine within the
        relevant source category" in determining if it is "routine." Further,
        the Federal EPA must calculate emissions by determining first whether a
        change in the maximum achievable hourly emission rate occurred as a
        result of the change, and then must calculate any change in annual
        emissions holding hours of operation constant before and after the
        change.

        On June 24, 2003, the United States Court of Appeals for the 11th
        Circuit issued an order invalidating the administrative compliance order
        issued by the Federal EPA to the Tennessee Valley Authority for similar
        alleged violations. The 11th Circuit determined that the administrative
        compliance order was not a final agency action, and that the enforcement
        provisions authorizing the issuance and enforcement of such orders under
        the Clean Air Act are unconstitutional.

        On June 26, 2003, the United States Court of Appeals for the District of
        Columbia Circuit granted a petition by the Utility Air Regulatory Group
        (UARG), of which the AEP subsidiaries are members, to reopen petitions
        for review of the 1980 and 1992 Clean Air Act rulemakings that are the
        basis for the Federal EPA claims in the AEP case and other related
        cases. On August 4, 2003, UARG filed a motion to separate and expedite
        review of their challenges to the 1980 and 1992 rulemakings from other
        unrelated claims in the consolidated appeal. The Circuit Court denied
        that motion on September 30, 2003. The central issue in these petitions
        concerns the lawfulness of the emissions increase test, as currently
        interpreted and applied by the Federal EPA in its utility enforcement
        actions. A decision by the D. C. Circuit Court could significantly
        impact further proceedings in the AEP case.

        On August 27, 2003, the Administrator of the Federal EPA signed a final
        rule that defines "routine maintenance repair and replacement" to
        include "functionally equivalent equipment replacement." Under the new
        final rule, replacement of a component within an integrated industrial
        operation (defined as a "process unit") with a new component that is
        identical or functionally equivalent will be deemed to be a "routine
        replacement" if the replacement does not change any of the fundamental
        design parameters of the process unit, does not result in emissions in
        excess of any authorized limit, and does not cost more than twenty
        percent of the replacement cost of the process unit. The new rule is
        intended to have prospective effect, and will become effective in
        certain states 60 days after October 27, 2003, the date of its
        publication in the Federal Register, and in other states upon completion
        of state processes to incorporate the new rule into state law. On
        October 27, 2003 twelve states, the District of Columbia and several
        cities filed an action in the United States Court of Appeals for the
        District of Columbia Circuit seeking judicial review of the new rule.

        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 that
        the AEP System companies do not prevail, any capital and operating costs
        of additional pollution control equipment that may be required, as well
        as any penalties imposed, would adversely affect future results of
        operations, cash flows and possibly financial condition unless such
        costs can be recovered through regulated rates and market prices for
        electricity.

        In December 2000, Cinergy Corp., an unaffiliated utility, which operates
        certain plants jointly owned by CSPCo, reached a tentative agreement
        with the Federal EPA and other parties to settle litigation regarding
        generating plant emissions under the Clean Air Act. Negotiations are
        continuing between the parties in an attempt to reach final settlement
        terms. Cinergy's settlement could impact the operation of Zimmer Plant
        and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%,
        respectively, by CSPCo). Until a final settlement is reached, CSPCo will
        be unable to determine the settlement's impact on its jointly owned
        facilities and its future results of operations and cash flows.


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

        The 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, the 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 the 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 the
        Federal EPA responds to the Court's remand. On April 30, 2002, the
        Federal EPA announced that May 31, 2004 is the compliance date for the
        Section 126 Rule. The 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 the 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 other combustion control technologies
        on a larger number of units. During 2001, 2002 and 2003, SCR technology
        commenced operations on units of Gavin, Amos, Mountaineer, Big Sandy
        and Cardinal plants. Construction of SCR technology at certain other
        AEP generating units continues. Other combustion control 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 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 $1 billion has been spent through
        September 30, 2003. Estimated compliance cost ranges and amounts spent
        by subsidiaries are as follows:

                           Estimated                       Amount
                        Compliance Costs                   Spent
                        ----------------                   -----
                                        (in millions)
               AEGCo          $28                             $7
               APCo           464                            283
               CSPCo           87                             68
               I&M             39                             12
               KPCo           180                            179
               OPCo         531-860                          431
               SWEPCo          35                             23
               TCC              5                              5




        Since compliance costs cannot be estimated with certainty, the actual
        cost to comply could be significantly different than these 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,
        these costs would adversely affect 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, including TCC and TNC, certain unaffiliated energy
        companies and ERCOT. The action alleges violations of the Sherman
        Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary
        duty, breach of contract, civil conspiracy and negligence. The
        allegations, not all of which are made against the AEP companies, range
        from anticompetitive bidding to withholding power. TCE alleges that
        these activities resulted in price spikes requiring TCE to post
        additional collateral and ultimately forced it into bankruptcy when it
        was unable to raise prices to its customers due to fixed price
        contracts. The suit alleges over $500 million in damages for all
        defendants and seeks recovery of damages, exemplary damages and court
        costs. This case is in the initial pleading stage. We have filed a
        Motion to Dismiss. The Court has set a hearing on the Motion to Dismiss
        for January 2004. Management believes that the claims against AEP and
        its subsidiaries are without merit. We intend 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 2003. We have developed
        financial requirements for security implementation and compliance with
        these NERC standards, the costs of which are not expected to be material
        to our future results of operations and cash flows.

6.      GUARANTEES
        ----------

        There are no liabilities recorded for guarantees entered into prior to
        December 31, 2002 by AEP's registrant subsidiaries in accordance with
        FIN 45. There are certain liabilities recorded for guarantees entered
        into subsequent to December 31, 2002. These liabilities are immaterial.
        There is no collateral held in relation to any guarantees and there is
        no recourse to third parties in the event any guarantees are drawn
        unless specified below.


        Letters of Credit

        Certain 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. At September 30, 2003,
        the maximum future payments of all the LOCs are approximately $181
        million with maturities ranging from September 30, 2003 to January 2011.
        Included in these amounts is TCC's LOC for credit enhancement of
        approximately $40.9 million with a maturity date of November 2003. As
        the parent of all these subsidiaries, AEP holds all assets of the
        subsidiaries as collateral. There is no recourse to third parties in the
        event these letters of credit are drawn.


        SWEPCo

        In connection with reducing the cost of the lignite mining contract for
        its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain
        conditions, to assume the obligations under 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 $60 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 September 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.

        On July 1, 2003, SWEPCo consolidated Sabine due to the application of
        FIN 46 (see Note 2). Upon consolidation, SWEPCo recorded the assets and
        liabilities of Sabine ($77.8 million). Also, after consolidation, SWEPCo
        currently records all expenses (depreciation, interest and other
        operation expense) of Sabine and eliminates Sabine's revenues against
        SWEPCo's fuel expenses. There is no cumulative effect of an accounting
        change recorded as a result of the requirement to consolidate, and there
        is no change in net income due to the consolidation of Sabine.


        Indemnifications and Other Guarantees

        AEP 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, exposure
        generally does not exceed the sale price. The subsidiaries cannot
        estimate the maximum potential exposure for any of these
        indemnifications entered into prior to December 31, 2002 due to the
        uncertainty of future events. In the first nine 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 into during the first nine
        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 September 30, 2003, the maximum potential loss
        by subsidiary for these lease agreements assuming the fair market value
        of the equipment is zero at the end of the lease term is as follows:


                                               Maximum Potential Loss
                   Subsidiary                      (in millions)
                   ----------                  ----------------------

                     APCo                               $ 1
                     CSPCo                                1
                     I&M                                  2
                     KPCo                                 1
                     OPCo                                 3
                     PSO                                  4
                     SWEPCo                               4
                     TCC                                  6
                     TNC                                  2

        See Note 8 "Leases" for disclosure of lease residual value guarantees.

7.      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.

8.      LEASES
        ------

        OPCo has entered into an agreement with JMG Funding LLP (JMG), an
        unrelated special purpose entity. JMG has a capital structure of which
        3% is equity from investors with no relationship to AEP or any of its
        subsidiaries and 97% is debt from commercial paper, pollution control
        bonds and other bonds. JMG was formed to design, construct and lease the
        Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber
        and leases it to OPCo. 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.

        On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46.
        Upon consolidation, OPCo recorded the assets and liabilities of JMG
        ($469.6 million). OPCo now records the depreciation, interest and other
        operating expenses of JMG and eliminates JMG's revenues against OPCo's
        operating lease expenses. There was no cumulative effect of an
        accounting change recorded as a result of our requirement to consolidate
        JMG, and there was no change in net income due to the consolidation of
        JMG.

        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.

9.      FINANCING AND RELATED ACTIVITIES
        --------------------------------

        Long-term debt and other securities issuances and retirements during the
        first nine months of 2003 were:
<TABLE>
<CAPTION>

                                                             Principal          Interest          Due
         Company                    Type of Debt              Amount              Rate            Date
         -------                    ------------             ---------          --------          ----
                                                           (in millions)           (%)
         Issuances:
             <C>               <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
             OPCo              Senior Unsecured Notes          225                4.85            2014
             OPCo              Senior Unsecured Notes          225                6.375           2033
             PSO               Senior Unsecured Notes          150                4.85            2010
             SWEPCo            Senior Unsecured Notes          100                5.375           2015
             SWEPCo            Secured Note of Subsidiary       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>
                                                             Principal          Interest          Due
         Company                    Type of Debt              Amount              Rate            Date
         -------                    ------------             ---------          -------           -----
                                                           (in millions)          (%)
        Retirements:

             <C>               <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
             APCo              Senior Unsecured Notes          125              Variable          2003
             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
             CSPCo             First Mortgage Bonds             25               6.60             2003
             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
             PSO               First Mortgage Bonds             65               7.25             2003
             SWEPCo            First Mortgage Bonds             55               6.625            2003
             SWEPCo            Secured Note of Subsidiary        2               4.47             2011
             SWEPCo            Notes Payable                     1              Variable          2008
             TCC               First Mortgage Bonds             18               7.50             2023
             TCC               First Mortgage Bonds             16               6.875            2003
             TCC               Securitization Bonds             51               3.54             2005
</TABLE>


        In addition to the transactions reported in the table above, the
        following table lists intercompany retirements of debt due to AEP:
<TABLE>
<CAPTION>

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

             <C>               <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>



        LINES OF CREDIT AND RELATED SHORT-TERM BORROWINGS
        -------------------------------------------------

        The AEP System Corporate Borrowing Program is the funding mechanism AEP
        uses to meet the short-term cash requirements of the system. The
        Corporate Borrowing Program consists of two primary funding groups: the
        AEP system Utility Money Pool, used by regulated companies, and the AEP
        system Non-Utility Money Pool, used by non-regulated companies. The AEP
        system Corporate Borrowing Program operates consistent with the terms
        and conditions outlined by the SEC. AEP has authority from the SEC
        through March 31, 2006 for short-term borrowings sufficient to fund the
        utility money pool and the non-utility money pool as well as its own
        requirements in an amount not to exceed $7.2 billion. Utility money pool
        participants include AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
        TCC and TNC (domestic utility companies). The following are the
        SEC-authorized limits for short-term borrowings for the domestic utility
        companies as of September 30, 2003:

                                                        Authorized
                                                        ----------
                                                       (in millions)
          AEP Generating                                    $125
          AEP Texas Central (a)                              600
          AEP Texas North (a)                                275
          Appalachian Power                                  600
          Columbus Southern Power (a)                        300
          Indiana Michigan Power                             500
          Kentucky Power                                     200
          Ohio Power (a)                                     250
          Public Service Company of
            Oklahoma                                         300
          Southwestern Electric Power                        350

        (a) Short term borrowing limits for these domestic utility companies are
        reduced by long-term debt issued commencing with the SEC order dated
        December 18, 2003, which authorized financing transactions through March
        31, 2006.


<PAGE>

           CONTROLS AND PROCEDURES


   During the third quarter of 2003, AEP's management, including the principal
   executive officer and principal financial officer, evaluated AEP'sdisclosure
   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 September 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 third 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 6 to AEP's
            consolidated financial statements and Note 5 to AEP's registrant
            subsidiaries' respective financial statements, both entitled
            Commitments and Contingencies, incorporated herein by reference.

  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 September 30, 2003.
<TABLE>
<CAPTION>
          Company Reporting         Date of Report          Item Reported
          -----------------         --------------          --------------

          <C>                      <C>                      <C>
          AEP                      July 30, 2003            Item 7. Financial Statements And Exhibits
                                                            Item 9. Regulation FD Disclosure




          OPCo                     July 8, 2003             Item 5. Other Events and Regulation FD Disclosure
                                                            Item 7. Financial Statements And Exhibits


          PSO                      September 10, 2003       Item 5. Other Events and Regulation FD Disclosure
                                                            Item 7. Financial Statements And Exhibits
</TABLE>
<PAGE>


                                        Signature




         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 signature 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/Joseph M. Buonaiuto
                                     -----------------------

                                     Joseph M. Buonaiuto
                                     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/Joseph M. Buonaiuto
                                      -----------------------

                                      Joseph M. Buonaiuto
                                      Controller and
                                      Chief Accounting Officer



 Date: November 12, 2003