<PAGE>
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                                                      UNITED STATES
                                           SECURITIES AND EXCHANGE COMMISSION
                                                  WASHINGTON, D.C. 20549
                                                       FORM 10-Q
                                   [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
                                         OF THE SECURITIES EXCHANGE ACT OF 1934
                                      For The Quarterly Period Ended JUNE 30, 2004
                                                           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 of Principal Executive Offices, and Telephone Number                        Identification No.
-----------                 ------------------------------------------------------------                        ------------------
<C>                         <C>                                                                                 <C>
1-3525                      AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)                      13-4922640
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 (An Oklahoma Corporation)                        73-0410895
1-3146                      SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)                        72-0323455

All Registrants             1 Riverside Plaza, Columbus, Ohio  43215-2373
                            Telephone (614) 716-1000

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

                                                                                                   Yes   X          No
                                                                                                       -----            -----

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

                                                                                                   Yes   X          No
                                                                                                       -----            -----

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

                                                                                                   Yes              No    X
                                                                                                       -----            -----

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






                                                               Number of Shares
                                                                of Common Stock
                                                                Outstanding at                Par Value at
                                                                July 30, 2004                 July 30, 2004
                                                               ----------------               -------------

<C>                                                              <C>                             <C>
American Electric Power Company, Inc.                            395,658,435                     $6.50

AEP Generating Company                                                 1,000                     1,000

AEP Texas Central Company                                          2,211,678                       25

AEP Texas North Company                                            5,488,560                       25

Appalachian Power Company                                         13,499,500                        -

Columbus Southern Power Company                                   16,410,426                        -

Indiana Michigan Power Company                                     1,400,000                        -

Kentucky Power Company                                             1,009,000                       50

Ohio Power Company                                                27,952,473                        -

Public Service Company of Oklahoma                                 9,013,000                       15

Southwestern Electric Power Company                                7,536,640                       18

</TABLE>
<PAGE>


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                     INDEX TO QUARTERLY REPORT ON FORM 10-Q
                                  June 30, 2004


Glossary of Terms
Forward-Looking Information

Part I.  FINANCIAL INFORMATION
  Items 1, 2 and 3 - Financial Statements, Management's Financial Discussion
  and Analysis and Quantitative and Qualitative Disclosures About Risk
  Management Activities:

  American Electric Power Company, Inc. and Subsidiary Companies:
       Management's Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Consolidated Financial Statements
       Notes to Consolidated Financial Statements

  AEP Generating Company:
       Management's Narrative Financial Discussion and Analysis
       Financial Statements

  AEP Texas Central Company and Subsidiary:
       Management's Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Consolidated Financial Statements

  AEP Texas North Company:
       Management's Narrative Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Financial Statements

  Appalachian Power Company and Subsidiaries:
       Management's Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Consolidated Financial Statements

  Columbus Southern Power Company and Subsidiaries:
       Management's Narrative Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Consolidated Financial Statements

  Indiana Michigan Power Company and Subsidiaries:
       Management's Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Consolidated Financial Statements

  Kentucky Power Company:
       Management's Narrative Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Financial Statements

  Ohio Power Company Consolidated:
       Management's Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Consolidated Financial Statements

  Public Service Company of Oklahoma:
       Management's Narrative Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Financial Statements

  Southwestern Electric Power Company Consolidated:
       Management's Financial Discussion and Analysis
       Quantitative and Qualitative Disclosures About Risk Management Activities
       Consolidated Financial Statements

  Notes to Financial Statements of Registrant Subsidiaries

  Registrant Subsidiaries' Combined Management's Discussion and Analysis

  Item 4.            Controls and Procedures

Part II.     OTHER INFORMATION
    Item 1.      Legal Proceedings
    Item 2.      Changes in Securities, Use of Proceeds and Issuer Purchases of
                 Equity Securities
    Item 4.      Submission of Matters to a Vote of Security Holders
    Item 5.      Other Information
    Item 6.      Exhibits and Reports on Form 8-K
                            (a)     Exhibits: Exhibit 12 Exhibit 31.1
                                    Exhibit 31.2 Exhibit 32.1 Exhibit
                                    32.2
                            (b)     Reports on Form 8-K O-4

SIGNATURE


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 other true-up items and the recovery of such amounts.
AEGCo                              AEP Generating Company, an electric utility subsidiary of AEP.
AEP                                American Electric Power Company, Inc.
AEP Consolidated                   AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit                         AEP Credit,  Inc., a subsidiary of AEP which factors  accounts  receivable and accrued utility
                                            revenues for affiliated domestic electric utility companies.
AEP East companies                 APCo, CSPCo, I&M, KPCo and OPCo.
AEPES                              AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEP System or the System           The American Electric Power System, an integrated electric utility system, owned and operated by
                                            AEP's electric utility subsidiaries.
AEPSC                              American Electric Power Service Corporation, a service subsidiary providing management and
                                            professional services to AEP and its subsidiaries.
AEP System Power Pool or           Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation
AEP Power Pool                              and resultant wholesale system sales of the member companies.
AEP West companies                 PSO, SWEPCo, TCC and TNC.
ALJ                                Administrative Law Judge.
APCo                               Appalachian Power Company, an AEP electric utility subsidiary.
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.).
DETM                               Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE                                United States Department of Energy.
EITF                               The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT                              The Electric Reliability Council of Texas.
FASB                               Financial Accounting Standards Board.
Federal EPA                        United States Environmental Protection Agency.
FERC                               Federal Energy Regulatory Commission.
GAAP                               Generally Accepted Accounting Principles.
I&M                                Indiana Michigan Power Company, an AEP electric utility subsidiary.
IURC                               Indiana Utility Regulatory Commission.
JMG                                JMG Funding LP.
KPCo                               Kentucky Power Company, an AEP electric utility subsidiary.
KPSC                               Kentucky Public Service Commission.
KWH                                Kilowatthour.
LIG                                Louisiana Intrastate Gas, an AEP subsidiary.
ME SWEPCo                          Mutual Energy SWEPCo L.P., a Texas retail electric provider.
Money Pool                         AEP System's Money Pool.
MTM                                Mark-to-Market.
MW                                 Megawatt.
MWH                                Megawatthour.
NOx                                Nitrogen oxide.
OATT                               Open Access Transmission Tariff.
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.
PUCT                               The Public Utility Commission of Texas.
PURPA                              The Public Utility Regulatory Policies Act of 1978.
Registrant Subsidiaries            AEP subsidiaries who are SEC registrants;  AEGCo,  APCo,  CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
                                            TCC and TNC.
Risk Management Contracts          Trading and non-trading derivatives, including those derivatives designated as cash flow and
                                            fair value hedges.
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 133                           Statement of Financial  Accounting  Standards No. 133,
                                            Accounting for Derivative  Instruments and Hedging Activities.
                                            --------------------------------------------------------------
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.
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.
VaR                                Value at Risk, a method to quantify risk exposure.
Virginia SCC                       Virginia State Corporation Commission.
Zimmer Plant                       William H.  Zimmer  Generating  Station,  a 1,300 MW  coal-fired  unit owned 25.4% by Columbus
                                            Southern Power Company, an AEP subsidiary.
</TABLE>
<PAGE>

                           FORWARD-LOOKING INFORMATION
                           ---------------------------

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

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

<PAGE>

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

EXECUTIVE OVERVIEW
------------------

Divestiture Plans
-----------------
As outlined in our 2003 Annual Report, we are continuing with our strategy of
disposing of various unregulated non-core businesses and assets in order to
focus management efforts on our core assets and operations and to eliminate
the negative earnings and cash consequences of these non-regulated operations.
We are also continuing the process of disposing of the generating assets of AEP
Texas Central Company (TCC) which will allow us to determine stranded costs for
recovery under Texas regulation.

During the first half of 2004, we (a) completed the sale of our interest in the
Pushan Power Plant, (b) closed on the sale of Louisiana Intrastate Gas Pipeline
Company and its approximately 2,000 miles of natural gas gathering and
transmission pipelines in Louisiana and five gas processing facilities that
straddle the system, and (c) completed the sale of assets, exclusive of certain
reserves and related liabilities, of the mining operations of AEP Coal. These
sales did not have a significant effect on our results of operations for the
second quarter 2004 or for the six months ended June 30, 2004.

In July 2004, we completed the sale of two coal-fired power plants in the U.K.
(Fiddler's Ferry in northwest England and Ferrybridge in northeast England),
related coal assets and a number of related commodities contracts. This sale
includes substantially all of our operations and assets in the Investments - UK
Operations segment. In July 2004, we also completed the sale of certain
generation assets within TCC, including eight natural gas plants, one coal-fired
plant and one hydro plant. We also closed on the sale of our ownership interests
in our two independent power producers in Florida and one in Colorado. We
anticipate the sale of our remaining independent power producer in Colorado will
be closed as soon as necessary regulatory approvals are obtained.

We are also making progress on the sale of our remaining TCC and non-core
assets. For TCC's assets, we have agreements for the sale of TCC's share of the
Oklaunion Power Station and TCC's share of the South Texas Project nuclear
plant. The co-owners of these facilities have notified TCC of their intentions
to exercise rights of first refusal, but we still expect to sell these assets
by the end of 2004. Nevertheless, there could be potential delays in receiving
necessary regulatory approvals and clearances which may delay the closings.
We also anticipate being able to reach an agreement for the sale of Jefferson
Island Storage and Hub, L.L.C., which holds the remaining LIG Pipeline Company
gas storage assets, by the end of the year.

We will continue to review our portfolio of businesses and assets for additional
divestiture opportunities which will further our goal of divesting of assets and
investments that are not a core part of our U.S. utility operations or are not
activities that will support or complement our regulatory utility business.

As indicated in our 2003 Annual Report, we are utilizing and will continue to
utilize the cash generated by the sale of certain assets to reduce existing
long-term debt and other obligations. During the six months ended June 30, 2004,
we reduced long-term debt by approximately $703 million. In July 2004, we
retired in excess of $500 million of additional long-term debt that we currently
do not plan to refinance, using cash on hand, proceeds from the issuance of
commercial paper and the net cash proceeds from the sale of certain Texas
generation assets. We anticipate further reductions of long-term debt over the
remainder of 2004. The result of our use of cash on hand and sales proceeds to
reduce debt has decreased our percentage of debt to total capitalization ratio
from 64.6% at December 31, 2003 to 63.3% at June 30, 2004.

Utility Operations
------------------
We continue to generate expected results from our Utility Operations as our net
income from Utility Operations was $183 million for the second quarter 2004 and
$486 million for the six-months ended June 30, 2004, although, these results are
not as strong when compared to the same periods in the prior year. Gross margins
improved in both periods driven by healthy utility sales increases in all
regions except Texas and improvements in the economy, but were more than offset
by increased expenses from outage maintenance and distribution system
reliability improvement work.

We made progress concerning regulatory challenges related to integration of the
AEP East companies into PJM (scheduled for October 1, 2004). A settlement
agreement was approved by the KPSC. A settlement was also reached with
interested parties in Virginia and is pending before the Virginia SCC for
approval. These settlements should allow the integration to proceed on time.

We announced during 2004 that we intend to invest approximately $3.5 billion on
environmental upgrades from 2004 to 2010 at our coal-fired generation plants in
order to continue our goal of producing low-cost electricity with minimal impact
on the environment. We continue to believe that investing in environmental
upgrades at existing plants is in the best interest of both our customers and
our business. Our commitment to make these investments is conditioned on
receiving appropriate recovery for our costs.

Texas Regulatory Activity
-------------------------
The issue of stranded cost recovery in Texas continues to be a major focus for
us. At June 30, 2004, we have recorded net regulatory assets of approximately
$1.4 billion in stranded costs and other amounts that TCC will seek recovery of
in the true-up proceeding before the PUCT. We currently expect our stranded cost
filing to request recovery of amounts in excess of our related regulatory
assets. Although we believe that the regulatory assets that we have recorded are
appropriate, the ultimate outcome of the true-up proceeding before the PUCT
could have a negative effect on our future results of operations, cash flows and
financial condition.

Common Stock Dividends
----------------------
After the completion of our planned divestitures and after the results of our
Ohio and Texas rate proceedings are known, we hope to be able to recommend to
the Board of Directors a moderate increase in our common stock dividend from its
current level of 35 cents per share per quarter.

Reorganization
--------------
In addition to the significant changes occurring as a result of our divestiture
plan, we also recently reorganized and put in place a new management team that
will place increased emphasis on our energy delivery and distribution activities
through our existing operating companies which have been organized into seven
regions. As a consequence, we appointed seven regional presidents and their
respective teams. They are in place and operating as of the end of July. These
seven new regional presidents and their management teams will focus on
responding more quickly to the needs of our customers in their regions. This
change supports our long-term focus of creating stronger utility businesses,
more in touch with the local needs of customers and regulators.

For additional information on our strategic outlook, see "Management's Financial
Discussion and Analysis of Results of Operations," including "Business
Strategy," in our 2003 Annual Report. Also see the remainder of our
"Management's Financial Discussion and Analysis of Results of Operations" in
this Form 10-Q, along with the Notes to Consolidated Financial Statements.

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

Segments
--------

AEP's principal operating business segments and their major activities are:

 o  Utility Operations:
    ------------------
    o  Domestic generation of electricity for sale to retail and
       wholesale customers
    o  Domestic electricity transmission and distribution

 o  Investments-Gas Operations:*
    --------------------------
    o  Gas pipeline and storage services

 o  Investments-UK Operations:**
    -------------------------
    o  International generation of electricity for sale to wholesale customers
    o  Coal procurement and transportation to AEP's U.K. plants

 o  Investments-Other:
    -----------------
    o  Bulk commodity barging operations, windfarms, independent power
       producers and other energy supply related businesses

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

There are numerous changes occurring in the businesses included in our segments
as a result of our continued divestiture of certain non-core operations.
Substantially all operations and assets within our Investments - UK Operations
segment were sold in July 2004. Within our Investments - Gas Operations segment,
we have recently sold LIG Pipeline Company, which included the gas pipeline
portion of Louisiana Intrastate Gas, and are currently marketing Jefferson
Island Storage & Hub, L.L.C., which holds the remaining Louisiana gas storage
assets held for sale. Upon completion of the divestiture of our non-core assets,
the only substantive portion of the Investments - Gas Operations business that
will remain is our Houston Pipe Line Company L.P. (HPL) operations, which
include the Bammel storage facility, and we will continue to operate HPL as we
evaluate our future plans for this investment.

In addition, there have been numerous divestitures of businesses, assets and
investments within our Investments - Other segment over the course of this past
year including AEP Coal and our interest in the Pushan Power Plant. Our goal for
the remaining assets in this segment, which includes our unregulated investments
in wind farms, and barging and river transportation groups, is to operate them
in such a way that they complement our core capabilities in regulated utility
operations.

All of the changes in these segments are leading us to review our business model
of the future and how we intend to manage our business overall. We intend to
make decisions over the course of the remainder of the year which may lead to
changes in our reported business segments.

AEP Consolidated Results
------------------------

American Electric Power Company's consolidated Net Income for the three and six
month periods ended June 30, 2004 and 2003 was as follows (Earnings and Average
Shares Outstanding in millions):

<TABLE>
<CAPTION>

                                                           Second Quarter                            Six Months Ended June 30,
                                           --------------------------------------------      ---------------------------------------
                                                   2004                     2003                    2004                  2003
                                                   ----                     ----                    ----                  ----

                                           Earnings      EPS       Earnings       EPS        Earnings    EPS      Earnings    EPS
                                           --------      ---       --------       ---        --------    ---      --------    ---
<C>                                          <C>        <C>          <C>         <C>           <C>      <C>         <C>      <C>
Utility Operations                           $183       $0.46        $225        $0.57         $486     $1.23       $531     $1.41
Investments - Gas Operations                   (4)      (0.01)        (25)       (0.06)         (13)    (0.03)       (43)    (0.11)
Investments - UK Operations                     -           -           -            -            -         -          -         -
Investments - Other                            (3)      (0.01)        (20)       (0.05)           1         -          -         -
All Other*                                    (25)      (0.06)         (3)       (0.01)         (34)    (0.09)       (18)    (0.05)
                                             -----      ------       -----       ------        -----    ------      -----    ------
Income Before Discontinued Operations
  and Cumulative Effect of Accounting
  Changes                                     151        0.38         177         0.45          440      1.11        470      1.25

Investments - Gas Operations                    2           -           1            -            1         -          4      0.01
Investments - UK Operations                   (52)      (0.13)          4         0.01          (64)    (0.16)       (37)    (0.09)
Investments - Other                            (1)          -          (7)       (0.02)           5      0.01        (15)    (0.04)
                                             -----      ------       -----       ------        -----    ------      -----    ------
Discontinued Operations                       (51)      (0.13)         (2)       (0.01)         (58)    (0.15)       (48)    (0.12)

Utility Operations                              -           -           -            -            -         -        236      0.63
Investments - Gas Operations                    -           -           -            -            -         -        (22)    (0.06)
Investments - UK Operations                     -           -           -            -            -         -        (21)    (0.06)
                                             -----      ------       -----       ------        -----    ------      -----    ------
Cumulative Effect of Accounting Changes         -           -           -            -            -         -        193      0.51
                                             -----      ------       -----       ------        -----    ------      -----    ------
Total Net Income                             $100       $0.25        $175        $0.44         $382     $0.96       $615     $1.64
                                             =====      ======       =====       ======        =====    ======      =====    ======

Average Shares Outstanding                                396                      395                    396                  376
                                                          ===                      ===                    ===                  ===
* All Other includes the parent company interest income and expense, as well as other non-allocated costs.

</TABLE>

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Income Before Discontinued Operations and Cumulative Effect of Accounting
Changes decreased $26 million to $151 million in 2004 compared to 2003. Net
Income for 2004 of $100 million or $0.25 per share includes a loss, net of
taxes, from discontinued operations of $51 million. Net Income for 2003 of $175
million or $0.44 per share includes a loss, net of taxes, from discontinued
operations of $2 million.

For the second quarter 2004 our Utility Operations Net Income decreased $42
million, or almost 19%, from the previous year driven by increased spending on
operations and maintenance expenses. Our UK Operations (which were sold on July
30, 2004) also contributed $56 million to the decrease in net income in the
second quarter 2004. Our Gas Operations and Other Investments segments posted
better results in 2004. Our Gas Operations segment benefited from increased
earnings from pipeline optimization and storage activities and lower operating
expenses, and our Investments - Other segment benefited from a reduction in our
provisions for uncollectible accounts receivable and lower overall expenses in
2004.

During the fourth quarter of 2003, we concluded that the UK Operations and LIG
were not part of our core business, and we began actively marketing each of
these investments for sale. The UK Operations consist of our generation and
trading operations that sell to wholesale customers and its coal procurement and
transportation operations. In July 2004, we completed the sale of substantially
all operations and assets within our Investments - UK Operations segment. LIG's
operations include 2,000 miles of intrastate gas pipelines, gas processing
facilities and a 9.7 billion cubic feet natural gas storage facility. LIG
Pipeline Company, which owned the pipeline and processing operations of LIG, was
sold in April 2004 (see Note 7).

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Income Before Discontinued Operations and Cumulative Effect of Accounting
Changes decreased $30 million to $440 million in 2004 compared to 2003. Net
Income for 2004 of $382 million or $0.96 per share includes a loss, net of
taxes, from discontinued operations of $58 million. Net Income for 2003 of $615
million or $1.64 per share includes a loss, net of taxes, from discontinued
operations of $48 million and a benefit from a net $193 million of cumulative
effect of changes in accounting related to asset retirement obligations and
accounting for risk management contracts.

For the six months ended June 30, 2004, Utility Operations Income Before
Discontinued Operations and Cumulative Effect of Accounting Changes decreased
$45 million or almost 8.5% from the previous year driven by increased spending
on operations and maintenance expenses. Our UK Operations (which were sold on
July 30, 2004) also were responsible for $6 million (including cumulative effect
of accounting changes) of the decrease in Net Income in 2004, while we sought a
buyer for our U.K. assets, all of which are part of discontinued operations. In
July 2004, we completed the sale of substantially all operations and assets
within our Investments - UK Operations segment. Our Investments-Gas Operations
segment posted a lower loss in 2004, benefiting from improved margins and
reductions in operating expenses.

Our results of operations by operating segment are discussed below.

<TABLE>
<CAPTION>

Utility Operations
------------------
                                                             Second Quarter                 Six Months Ended June 30,
                                                     ------------------------------         -------------------------
                                                      2004                  2003            2004                2003
                                                      ----                  ----            ----                ----
                                                                                (in millions)
<C>                                                  <C>                   <C>              <C>                <C>
Revenues                                             $2,544                $2,665           $5,149             $5,371
Fuel and Purchased Power                                821                   956            1,581              1,846
                                                     -------               -------          -------            -------
Gross Margin                                          1,723                 1,709            3,568              3,525
Depreciation and Amortization                           308                   315              618                610
Other Operating Expenses                                998                   889            1,911              1,760
                                                     -------               -------          -------            -------
Operating Income                                        417                   505            1,039              1,155
Other Income (Expense), Net                              16                     5               25                  3
Interest Expense and Preferred
   Stock Dividend Requirements                          157                   167              320                331
Income Tax Expense                                       93                   118              258                296
                                                     -------               -------          -------            -------
Income Before Discontinued
   Operations and Cumulative Effect                    $183                  $225             $486               $531
                                                     =======               =======          =======            =======

</TABLE>
<TABLE>
<CAPTION>

                                     Summary of Selected Sales Data
                                         For Utility Operations

                                      Second Quarter                 Six Months Ended June 30,
                                  -----------------------            -------------------------

                                   2004            2003               2004              2003
                                   ----            ----               ----              ----
<C>                               <C>             <C>                <C>              <C>
Energy Summary                                       (in millions of KWH)
Retail
  Residential                      9,740           8,659             23,167           22,080
  Commercial                       9,390           8,773             18,169           17,568
  Industrial                      12,902          12,449             25,175           24,455
  Miscellaneous                      806             734              1,549            1,424
                                  -------         -------            -------          -------
       Subtotal                   32,838          30,615             68,060           65,527
Texas Retail and Other               262             739                486            1,538
                                  -------         -------            -------          -------
           Total                  33,100          31,354             68,546           67,065
                                  =======         =======            =======          =======

Wholesale                         19,884          16,357             39,225           36,716
                                  =======         =======            =======          =======

</TABLE>
<TABLE>
<CAPTION>

                                      Second Quarter                 Six Months Ended June 30,
                                  -----------------------            -------------------------

                                   2004            2003               2004              2003
                                   ----            ----               ----              ----
Weather Summary                                         (in degree days)

Eastern Region
--------------
<C>                                 <C>             <C>              <C>                <C>
Actual - Heating                    167             141              2,031              2,169
Normal - Heating*                   180              **              1,986                 **

Actual - Cooling                    313             157                316                158
Normal - Cooling*                   278              **                281                 **

Western Region (PSO/SWEPCo)
---------------------------
Actual - Heating                     30              34                913              1,074
Normal - Heating*                    33              **              1,012                 **

Actual - Cooling                    659             638                689                644
Normal - Cooling*                   642              **                660                 **

* Normal Heating/Cooling represents the 30-year average of degree days.
**Not meaningful.
</TABLE>


Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Income from Utility Operations decreased $42 million to $183 million in 2004.
The key driver of the decrease was a $109 million increase in other operating
expenses, partially offset by a $14 million increase in gross margin, a $25
million decrease in income taxes, and a $28 million net decrease in other
expenses.

The major components of our change in gross margin, defined as utility revenues
net of related fuel and purchased power, were as follows:

 o  Overall retail margins (excluding fuel recovery) in our utility business
    increased $47 million. Residential demand increased over the prior year as
    a consequence of higher usage by customers resulting from favorable weather.
    Cooling degree days were up significantly in the East and off slightly in
    the West. Heating degree days were up in the East and off slightly in the
    West as compared to the prior year. Commercial and industrial demand also
    increased resulting from the economic recovery in our regions.
 o  Fuel recovery in our non-Texas utility business was a net $37 million
    favorable in comparison to last year primarily due to higher fuel costs
    in the prior year resulting from the conclusion of the amortization of Cook
    plant outage costs and a fish intrusion outage causing us to purchase higher
    priced non-nuclear power in 2003.
 o  Our Texas supply business had a $31 million decrease in gross margin
    principally due to a $52 million decrease resulting from increased
    provisions for potential fuel disallowances in Texas, offset by a $21
    million increase from a favorable adjustment recorded in 2004 to a retail
    clawback refund related to the number of customers receiving price-to-beat
    service in Texas.
 o  Beginning in 2004, the wholesale capacity auction true-up ceased per rules
    of the PUCT, therefore revenues are no longer recognized, resulting in
    $52 million of lower regulatory deferrals in 2004. For the years 2003 and
    2002, we recognized the non-cash revenues for the wholesale capacity
    auction true-up for TCC as a regulatory asset for the difference between
    the actual market prices based upon the state-mandated auction of 15% of
    generation capacity and the earlier estimate of market price used in the
    PUCT's excess cost over market model.
 o  Margins from off-system  sales for 2004 were $9 million better than 2003
    due to favorable power and coal optimization activity, slightly offset by
    lower volumes.

Utility operating expenses and income tax expense changed between years as
follows:

 o  Maintenance and Other Operation expense increased $89 million due to a $33
    million increase from the timing of planned plant outages in 2004 as
    compared to 2003, $29 million of increased distribution maintenance expense
    primarily from storm damage and system reliability work, and a $14 million
    net increase in employee-related benefits and insurance, magnified by
    favorable adjustments in 2003. These increases were offset, in part, by
    $10 million due to the conclusion of the amortization of our deferred Cook
    nuclear plant restart settlement expenses. Expenses of $23 million,
    comprised of several miscellaneous items, make up the remainder of the
    increase.
 o  Income Tax Expense decreased $25 million almost entirely due to the
    decrease in pre-tax income.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Income from Utility Operations, before $236 million of cumulative effect of
accounting changes in 2003, decreased $45 million to $486 million in 2004. Key
drivers of the change include a $151 million increase in Other Operating
Expenses, offset by a $43 million increase in gross margin, a $38 million
decrease in income taxes, a $22 million increase in net other income and a $3
million net decrease in other expense line items.

The major components of our change in gross margin, defined as utility revenues
net of related fuel and purchased power, were as follows:

 o  Overall retail margins (excluding fuel recovery) in our utility business
    increased $63 million. Residential demand in the East increased over the
    prior year as a consequence of higher usage by customers partially
    resulting from favorable weather while demand in the West was off slightly.
    Cooling degree days were up significantly in the East and up slightly in
    the West. Heating degree days were off slightly in the East and off in the
    West as compared to the prior year. Overall commercial and industrial
    demand also increased resulting from the economic recovery in our regions.
 o  Fuel recovery in our non-Texas utility business was a net $59 million
    favorable in comparison to last year primarily due to higher fuel costs in
    the prior year resulting from the conclusion of the amortization of
    deferred Cook plant outage costs and a fish intrusion outage causing us
    to purchase higher priced non-nuclear replacement power in 2003.
 o  Our Texas supply business had a $43 million decrease in gross margin
    principally due to a $27 million decrease resulting from increased
    provisions for potential fuel disallowances in Texas, a $31 million impact
    from lower Reliability-Must-Run (RMR) contract margins, and a $16 million
    unfavorable variance due to declining commercial and industrial business in
    Texas, offset by a $21 million increase from a favorable adjustment recorded
    in 2004 to a retail clawback refund related to the number of customers
    receiving price-to-beat service in Texas.
 o  Beginning in 2004, the wholesale capacity auction true-up ceased per rules
    of the PUCT, therefore revenues are no longer recognized, resulting in
    $108 million of lower regulatory deferrals in 2004. For the years 2003 and
    2002, we recognized the non-cash revenues for the wholesale capacity
    auction true-up for TCC as a regulatory asset for the difference between
    the actual market prices based upon the state-mandated auction of 15% of
    generation capacity and the earlier estimate of market price used in the
    PUCT's excess cost over market model.
 o  Margins from off-system sales for 2004 were $60 million better than in 2003
    due to favorable power and coal optimization activity, slightly offset by
    lower volumes.

Utility operating expenses and income tax expense changed between years as
follows:

 o  Maintenance and Other Operation expense increased $135 million due to a
    $63 million increase from the timing of planned plant outages in 2004
    as compared to 2003, $28 million of increased distribution maintenance
    expense from system reliability work and a $30 million net increase in
    employee-related benefits, insurance and other administrative expenses
    magnified by favorable adjustments in 2003. These increases were offset,
    in part, by $20 million due to the conclusion of the amortization of our
    deferred Cook nuclear plant restart settlement expenses. Expenses of
    $34 million, comprised of several miscellaneous items, make up the
    remainder of the increase.
 o  The remaining $16 million of the increase in Other Operating Expenses was a
    result of an increase in taxes other than income taxes.
 o  Income Tax Expense decreased $38 million due to the decrease in pre-tax
    income and other tax return adjustments.

<TABLE>
<CAPTION>

Investments - Gas Operations
----------------------------
                                                          Second Quarter                Six Months Ended June 30,
                                                      ---------------------             -------------------------
                                                      2004             2003             2004                 2003
                                                      ----             ----             ----                 ----
                                                                            (in millions)
<C>                                                  <C>               <C>              <C>                 <C>
Revenue                                              $817              $675             $1,468              $1,623
Purchased Gas                                         773               684              1,385               1,574
                                                     -----             -----            -------             -------
Gross Margin                                           44                (9)                83                  49
Maintenance and Other Operation                        31                36                 60                  74
Other Operating Expense                                 3                 6                  6                  11
                                                     -----             -----            -------             -------
Operating Income (Loss)                                10               (51)                17                 (36)
Other Income (Expense), Net                            (3)                1                 (9)                 (5)
Interest Expense                                       13                14                 25                  26
Income Tax Benefit                                      2                39                  4                  24
                                                     -----             -----            -------             -------
Net Loss Before Discontinued Operations and
 Cumulative Effect                                    $(4)             $(25)              $(13)               $(43)
                                                     =====             =====            =======             =======

</TABLE>

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Our $4 million loss from Gas Operations before discontinued operations and
cumulative effect of accounting changes compares with a $25 million loss
recorded in the second quarter of 2003. Gross margins improved $53 million
year-over-year driven by improvements in our earnings from pipeline optimization
and storage activities. Operating expenses decreased by $8 million as a result
of reduced gas trading activities and lower depreciation resulting from 2003
asset impairments. Income tax benefits decreased by $37 million due to the
improvement in pre-tax income and a $16 million tax benefit adjustment from a
capital loss recorded in the second quarter of 2003.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Our $13 million loss from Gas Operations before discontinued operations and
cumulative effect of accounting changes compares with a $43 million loss
recorded in the year-to-date June 2003 period. Gross margins improved $34
million year-to-date June 30, 2004 to $83 million. The increase in margins were
driven by $20 million of significant losses in 2003 from servicing a single
contract when gas prices were at an all time high, and $6 million higher
pipeline and pipeline optimization margins in 2004. In addition, operating
expenses decreased $19 million between periods due to reduced gas trading
activities and lower depreciation resulting from 2003 asset impairments. Income
tax benefits decreased by $20 million primarily due to the improvement in
pre-tax income.

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

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Our UK Operations (all classified as Discontinued Operations) incurred a loss of
$52 million for 2004 compared with income of $4 million in 2003. During late
2003, we concluded that the UK Operations were not part of our core business and
we began actively marketing our investment. In July 2004, we completed the sale
of substantially all operations and assets within our Investments - UK
Operations segment.

Our UK Operations' gross margins from generation increased $11 million in 2004,
reflecting the improvement in wholesale electricity prices in the U.K. These
improvements were offset by a $32 million decrease in margins from risk
management activity primarily resulting from AEP's decision to exit trading in
the first quarter of 2004 and the closure and settlement of non-core and
residual positions, as well as an increase of $37 million in maintenance and
other operation expense due to several factors, including the expensing of
capital expenditures during held-for-sale status to maintain the appropriate
fair value of the fixed assets and higher connection charges resulting from a
re-zoning of the plants.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Our UK Operations (all classified as Discontinued Operations) incurred a loss of
$64 million for 2004 compared with a loss of $37 million in 2003, before the
cumulative effect of accounting change. During late 2003, we concluded that the
UK Operations were not part of our core business and we began actively marketing
our investment. In July 2004, we completed the sale of substantially all
operations and assets within our Investments - UK Operations segment.

Our UK Operations' gross margins from generation increased $40 million as a
result of a 4% increase in generation and favorable price variances. Risk
management margin was lower by $63 million resulting from AEP exiting trading in
the first quarter of 2004 and the closure and settlement of non-core and
residual positions. Operating expenses were unfavorable by $33 million due to
several factors, including the expensing of capital expenditures during the
held-for-sale status to maintain the appropriate fair value of the fixed assets
and higher connection charges resulting from a re-zoning of the plants.
Depreciation and amortization decreased $10 million due to the cessation of
plant depreciation due to the held-for-sale status of assets.

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

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Loss before discontinued operations and cumulative effect of accounting changes
from our Investments - Other segment decreased by $17 million to $3 million in
2004.

The decrease in the loss is due to the following:

 (a)  Our AEP Texas  Provider of Last Resort (POLR) entity  recorded a $6
      million  provision for  uncollectible  receivables in the second quarter
      2003 that did not reoccur in 2004,
 (b)  Our AEP Resources entity decreased its loss by $7 million in the second
      quarter 2004 as compared to 2003 primarily due to lower interest expense
      resulting from equity capital infusions in mid and late 2003
      that were used to reduce debt and other corporate borrowings, and
 (c)  Our AEP Pro Serv entity reduced losses from $4 million to break even,
      primarily due to operations winding down in 2004.

In addition to the items above, the results from our IPPs and windfarms
decreased $3 million primarily driven by an additional $1.6 million impairment
recorded by one of our Colorado IPPs in June 2004 and an additional $1 million
of expense related to unfavorable unit outages at our Mulberry unit in Florida
and maintenance at our Sweeney unit in Texas. These decreases of $3 million
were equally offset by other insignificant increases at other investment
entities.

In discontinued operations, Eastex was sold in the third quarter 2003 and Pushan
Power Plant was sold in March 2004.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Income before discontinued operations and cumulative effect of accounting
changes from our Investments - Other segment increased from no income to $1
million of income in 2004.

The key components of the increase in income were as follows:

 (a)  Our AEP Texas Provider of Last Resort (POLR) entity  recorded a $6
      million  provision for  uncollectible  receivables in the first six
      months of 2003 that did not reoccur in 2004,
 (b)  Our AEP Resources entity decreased their loss by $17 million for the
      first six months of 2004 versus 2003, primarily due to lower interest
      expense resulting from equity capital infusions in mid and late 2003
      that were used to reduce debt and other corporate borrowings,
 (c)  Our AEP Pro Serv entity reduced losses from $4 million to break even,
      primarily due to operations winding down in 2004, and
 (d)  Our other entities had individually insignificant changes in results
      totaling a net $5 million increase in income between years.

Offsetting these increases was a $31 million nonrecurring gain recorded in the
first quarter of 2003 primarily related to a gain from the sale of Mutual
Energy.

In discontinued operations, Eastex was sold in the third quarter 2003 and Pushan
Power Plant was sold in March 2004.

All Other
---------

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Our parent company's second quarter 2004 expenses increased $22 million over the
second quarter 2003 resulting primarily from a $6 million decrease in interest
income generated from a lower average intercompany debt receivable balance and
lower net invested cash during the quarter, a $7 million increase in interest
expense resulting primarily from accelerated discount amortization from the
early redemption of senior notes in May 2004, a $2 million decrease in parent
guarantee fee income, and an additional net $7 million increase in other
expenses, none individually significant.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Our parent company's year-to-date 2004 expenses increased $16 million over the
year-to-date 2003 time period primarily due to a $17 million decrease in
interest income generated from a lower average intercompany debt receivable
balance and lower net invested cash during the six months in 2004, a $3 million
decrease in parent guarantee fee income, and a $2 million increase in other
expenses, partially offset by a $6 million decrease in operations and
maintenance expense resulting from lower general advertisement expenses in 2004.

Income Taxes
------------

The effective tax rates for the second quarter of 2004 and 2003 were 34.1% and
24.7%, respectively. The increase in the effective tax rate is primarily due to
realizing a tax benefit from a capital loss in the second quarter of 2003. The
difference in the effective income tax rate and the federal statutory rate of
35% is due to flow-through of book versus tax differences, permanent
differences, energy production credits, amortization of investment tax credits
and state income taxes.

The effective tax rates for the first six months of 2004 and 2003 were 35.3% and
35.4%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, permanent differences, energy production credits, amortization of
investment tax credits and state income taxes. The effective tax rates remained
flat for the comparative period.

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

We measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.

Capitalization
--------------
<TABLE>
<CAPTION>

                                                          June 30,    December 31,
                                                            2004         2003
                                                          --------    ------------
<C>                                                        <C>          <C>
Common Equity                                               36.4%        35.1%
Preferred Stock                                              0.3          0.3
Preferred Stock (Subject to Mandatory Redemption)            0.3          0.3
Long-term Debt, including amounts due within one year       60.3         62.8
Short-term Debt                                              2.7          1.5
                                                           ------       ------

Total Capitalization                                       100.0%       100.0%
                                                           ======       ======
</TABLE>

Our $1.3 billion in cash flows from operations, combined with our reduction in
cash expenditures for investments in discontinued operations, a second quarter
of 2003 reduction in dividends paid and the use of a portion of our cash on
hand, allowed us to reduce long-term debt by $703 million, while only increasing
short-term debt by $270 million. Our common equity percentage benefited from the
issuance of $11 million of new common equity (related to our incentive
compensation plans) and the fact that our earnings exceeded our dividends for
the six months ended June 30, 2004. As a consequence of the capital changes
during the six months, we improved our ratio of debt to total capital from
64.6% to 63.3% (preferred stock subject to mandatory redemption is included in
debt component of ratio).

In July 2004, we retired in excess of $500 million of long-term debt that we
currently do not plan to refinance, using cash on hand, proceeds from the
issuance of commercial paper and a portion of the net cash proceeds from the
sale of certain Texas generation assets.

Liquidity
---------

Liquidity, or access to cash, is an important factor in determining our
financial stability. We are committed to preserving an adequate liquidity
position.

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

We manage our liquidity by maintaining adequate external financing commitments.
We had an available liquidity position, at June 30, 2004, of approximately $3.4
billion as illustrated in the table below.

                                                      Amount      Maturity
                                                      ------      --------
                                                   (in millions)
Commercial Paper Backup:
  Lines of Credit                                     $1,000      May 2005
  Lines of Credit                                        750      May 2006
  Lines of Credit                                      1,000      May 2007
Euro Revolving Credit
  Facility                                               184      October 2004
Letter of Credit Facility                                200      September 2006
                                                      ------
Total                                                  3,134
Cash and Cash Equivalents                                858
                                                      ------
Total Liquidity Sources                                3,992
Less: AEP Commercial Paper
           Outstanding                                   554(a)
         Letters of Credit
           Outstanding                                    52
                                                      ------

Net Available Liquidity at June 30, 2004              $3,386
                                                      ======

 (a) Amount does not include JMG Funding LP commercial paper outstanding
     in the amount of $21 million. This commercial paper is specifically
     associated with the Gavin scrubber lease and does not reduce available
     liquidity to AEP.

Debt Covenants and Borrowing Limitations
----------------------------------------

Our revolving credit agreements require us to maintain our percentage of debt to
total capitalization at a level that does not exceed 67.5%. The method for
calculating our outstanding debt and other capital is contractually defined. At
June 30, 2004, we were in compliance with the covenants contained in these
credit agreements and debt to total capitalization was 58.0%. Non-performance of
these covenants could result in an event of default under these credit
agreements. In addition, the acceleration of our payment obligations, or certain
obligations of our subsidiaries, prior to maturity under any other agreement or
instrument relating to debt outstanding in excess of $50 million would cause an
event of default under these credit agreements and permit the lenders to declare
the amounts outstanding thereunder payable.

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

Under an SEC order, we and our utility subsidiaries cannot incur additional
indebtedness if the issuer's common equity would constitute less than 30% (25%
for TCC) of its capital. In addition, this order restricts us and our utility
subsidiaries from issuing long-term debt unless that debt will be rated
investment grade by at least one nationally recognized statistical rating
organization. At June 30, 2004, we were in compliance with this order.

Money pool and external borrowings may not exceed SEC or state commission
authorized limits. At June 30, 2004, we had not exceeded the SEC or state
commission authorized limits.

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

We continue to take steps to improve our credit quality, including plans during
2004 to further reduce our outstanding debt through the use of proceeds from our
planned dispositions and the use of cash on hand. Our ratings have not been
adjusted by any rating agency during 2004. On August 2, 2004, Moody's Investors
Service (Moody's) changed their ratings outlook on AEP to "positive" from
"stable," while keeping the remaining rated subsidiaries on "stable" outlook.
The other major rating agencies currently have AEP and our rated subsidiaries on
"stable" outlook. Our current ratings by the major agencies 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


If we receive a downgrade in our credit ratings by one of the nationally
recognized rating agencies listed above, our borrowing costs could increase and
access to borrowed funds could be negatively affected.

Common Stock Dividends
----------------------

After the completion of our planned divestitures and after the results of our
Ohio and Texas rate proceedings are known, we hope to be able to recommend to
the Board of Directors a moderate increase in our common stock dividend from
its current level of 35 cents per share per quarter.

Cash Flow
---------

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

                                                       Six Months Ended June 30,
                                                        2004             2003
                                                        ----             ----
                                                            (in millions)
Cash and Cash Equivalents at Beginning of Period        $976            $1,088
                                                       ------           -------
Net Cash Flows From Operating Activities               1,262               850
Net Cash Flows Used For Investing Activities            (575)           (1,288)
Net Cash Flows From (Used For) Financing Activities     (805)              420
                                                       ------           -------
Net Decrease in Cash and Cash Equivalents               (118)              (18)
                                                       ------           -------
Cash and Cash Equivalents at End of Period              $858            $1,070
                                                       ======           =======


In addition to cash on hand, cash from operations, combined with a
bank-sponsored receivables purchase agreement and short-term borrowings, provide
necessary working capital and help us meet other short-term cash needs.

We use our corporate borrowing program to meet the short-term borrowing needs of
our subsidiaries. The corporate borrowing program includes a utility money pool,
which funds the utility subsidiaries, and a non-utility money pool, which funds
the majority of the non-utility subsidiaries. In addition, we also fund, as
direct borrowers, the short-term debt requirements of our other subsidiaries
that are not participants in the non-utility money pool. As of June 30, 2004, we
had credit facilities totaling $2.75 billion to support our commercial paper
program. At June 30, 2004, AEP had $596 million outstanding in short-term
borrowings of which $554 million was commercial paper supported by the revolving
credit facilities. In addition, JMG had commercial paper outstanding in the
amount of $21 million. This commercial paper is specifically associated with the
Gavin scrubber lease and is not supported by our credit facilities. The maximum
amount of AEP commercial paper outstanding during the quarter ended June 30,
2004 was $661 million. The weighted-average interest rate for our commercial
paper during the second quarter 2004 was 1.42%.

We generally use short-term borrowings to fund working capital needs, property
acquisitions and construction until long-term funding mechanisms are arranged.
Sources of long-term funding include issuance of common stock, preferred stock
or long-term debt and sale-leaseback or leasing agreements.

Operating Activities
--------------------
                                                      Six Months Ended June 30,
                                                       2004              2003
                                                       ----              ----
                                                           (in millions)
Net Income                                             $382              $615
Plus: Losses from Discontinued Operations                58                48
                                                     -------             ----
Income from Continuing Operations                       440               663
Noncash Items Included in Earnings                      766               462
Changes in Assets and Liabilities                        56              (275)
                                                     -------             -----
Net Cash Flows From Operating Activities             $1,262              $850
                                                     =======             =====

2004 Operating Cash Flow
------------------------

Our cash flows from operating activities were $1,262 million for the first six
months of 2004. We produced income from continuing operations of $440 million
during the period. Income from continuing operations for the period included
noncash expense items of $716 million for depreciation, amortization and
deferred taxes. In addition, there is a current period impact for a net $50
million balance sheet change for risk management contracts that are
marked-to-market. These contracts have an unrealized earnings impact as market
prices move, and a cash impact upon settlement or upon disbursement or receipt
of premiums. The other changes in assets and liabilities represent items that
had a current period cash flow impact, such as changes in working capital, as
well as items that represent future rights or obligations to receive or pay
cash, such as regulatory assets and liabilities. The current period activity in
these asset and liability accounts relates to a number of items; the most
significant are an increase in the balance of fuel, materials and supplies of
$196 million, and an increase in the balance of accrued taxes of $140 million.

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

Our cash flows from operating activities were $850 million for the first six
months of 2003. We produced income from continuing operations of $663 million
during the period. Income from continuing operations for the period included
noncash items of $668 million for depreciation, amortization, and deferred
taxes, and $193 million related to the cumulative effect of accounting changes.
There was a current period impact for a net $33 million balance sheet change for
risk management contracts that were marked-to-market. These contracts have an
unrealized earnings impact as market prices move, and a cash impact upon
settlement or upon disbursement or receipt of premiums. The other activity in
the asset and liability accounts related to the wholesale capacity auction
true-up asset (ECOM) of $108 million, increases in customer deposits and risk
management collateral of $167 million, increases in accrued taxes of $62 million
and changes in accounts receivable and accounts payable of $145 million.

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

                                                   Six Months Ended June 30,
                                                    2004             2003
                                                    ----             ----
                                                        (in millions)

Construction Expenditures                          $(697)            $(639)
Change in Other Cash Deposits, Net                    (2)               23
Investment in Discontinued Operations, net             -              (716)
Proceeds from Sale of Assets                         131                41
Other                                                 (7)                3
                                                   ------          --------
Net Cash Flows Used for Investing Activities       $(575)          $(1,288)
                                                   ======          ========

Our cash flows used for investing activities decreased $713 million from the
same period in the prior year primarily due to investments made in our U.K.
operations during 2003 that did not recur during 2004.

Financing Activities
--------------------
                                                     Six Months Ended June 30,
                                                      2004             2003
                                                      ----             ----
                                                          (in millions)
Issuances of Common Stock                              $11           $1,142
Issuances/Retirements of Debt, net                    (535)            (153)
Retirement of Preferred Stock                           (4)              (2)
Retirement of Minority Interest                          -             (225)
Dividends                                             (277)            (342)
                                                     ------          -------
Net Cash Flows From (Used for)
 Financing Activities                                $(805)            $420
                                                     ======          =======

Our cash flow from financing activities in 2004 decreased $1.2 billion from the
$420 million net cash inflow recorded in 2003. During the first quarter of 2003,
we issued common stock for $1,142 million and subsequent to the first quarter of
2003, we reduced our dividend. This compares to only $11 million of cash
proceeds from the issuance of common stock under our incentive compensation
plans in the first six months of 2004.

During the first six months of 2004, we used approximately $986 million of cash
to retire long-term debt. We also issued approximately $268 million of long-term
debt ($263 million net of issuance costs) including $173 million of pollution
control bonds (installment purchase contracts). These activities were supported
by the generation of $1.3 billion in cash flow from operations. See Note 10
"Financing Activities" for further information regarding issuances and
retirements of debt instruments during the first six months of 2004.

Off-balance Sheet Arrangements
------------------------------

In prior years, we entered into off-balance sheet arrangements for various
reasons including accelerating cash collections, reducing operational expenses
and spreading risk of loss to third parties. Our off-balance sheet arrangements
have not changed significantly from year-end 2003 and are comprised of a sale
of receivables agreement maintained by AEP Credit, a sale and leaseback
transaction entered into by AEGCo and I&M with an unrelated unconsolidated
trustee, and an agreement with an unrelated, unconsolidated leasing company to
lease coal-transporting aluminum railcars. Our current policy restricts the use
of off-balance sheet financing entities or structures, except for traditional
operating lease arrangements and sales of customer accounts receivable that are
entered into in the normal course of business. For complete information on each
of these off-balance sheet arrangements see the "Minority Interest and
Off-balance Sheet Arrangements" in "Management's Financial Discussion and
Analysis of Results of Operations" section of the 2003 Annual Report.

Other
-----

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

We have agreements with Juniper Capital L.P. (Juniper) under which Juniper
constructed and financed a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and leased the Facility to us. We have
subleased the Facility to the Dow Chemical Company (Dow). The Facility is a
Dow-operated "qualifying cogeneration facility" for purposes of PURPA.
Commercial operation of the Facility as required by the agreements between
Juniper, AEP and Dow was achieved on March 18, 2004. The initial term of our
lease with Juniper (Juniper Lease) commenced on March 18, 2004 and terminates on
June 17, 2009. We may extend the term of the Juniper Lease for up to 30 years.
Our lease of the Facility is reported as an owned asset under a lease financing
transaction. Therefore, the asset and related liability for the debt and equity
of the facility are recorded on AEP's balance sheet.

Juniper is an unaffiliated limited partnership, formed to construct or otherwise
acquire real and personal property for lease to third parties, to manage
financial assets and to undertake other activities related to asset financing.

At June 30, 2004, Juniper's acquisition costs for the Facility totaled $520
million, and we estimate total costs for the completed Facility to be
approximately $525 million, funded through long-term debt financing of $494
million and equity of $31 million from investors with no relationship to AEP or
any of AEP's subsidiaries. For the initial 5-year lease term, the base lease
rental is equal to the interest on Juniper's debt financing at a variable rate
indexed to three-month LIBOR (1.61% as of June 30, 2004) plus 100 basis points,
plus a fixed return on Juniper's equity investment in the Facility and certain
other fixed amounts. Consequently, as LIBOR increases, the base rental payments
under the Juniper Lease will also increase.

The Facility is collateral for Juniper's debt financing. Due to the treatment of
the Facility as a financing of an owned asset, we recognized all of Juniper's
obligations as a liability of $520 million. Upon expiration of the lease,
our actual cash obligation could range from $0 to $415 million based upon the
fair value of the assets at that time. However, if we default under the Juniper
Lease, our maximum cash payment could be as much as $525 million.

Dow uses a portion of the energy produced by the Facility and sells the excess
energy. OPCo has agreed to purchase up to approximately 800 MW of such excess
energy from Dow. Because the Facility is a major steam supply for Dow, Dow is
expected to operate the Facility at certain minimum levels, and OPCo is
obligated to purchase the energy generated at those minimum operating levels
(expected to be approximately 270 MW).

OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel
Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and
Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in
excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity,
energy and ancillary services to TEM pursuant to the PPA that TEM rejected as
non-conforming. Commercial operation for purposes of the PPA began April 2,
2004.

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

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

On March 26, 2004, OPCo requested that TEM provide assurances of performance of
its future obligations under the PPA, but TEM refused to do so. As indicated
above, OPCo also gave notice to TEM and declared April 2, 2004 as the
"Commercial Operations Date." Despite OPCo's prior tenders of replacement
electric power products to TEM beginning May 1, 2003 and despite OPCo's tender
of electric power products from the Facility to TEM beginning April 2, 2004, TEM
refused to accept and pay for them under the terms of the PPA. On April 5, 2004,
OPCo gave notice to TEM that OPCo (i) was suspending performance of its
obligations under PPA, (ii) would be seeking a declaration from the New York
federal court that the PPA has been terminated and (iii) would be pursuing
against TEM and Tractebel SA under the guaranty damages and the full termination
payment value of the PPA.

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

Progress Made on Announced Divestitures
---------------------------------------

We are continuing with our announced plan to divest significant components of
our non-regulated assets, including certain domestic and international
unregulated generation, part of our gas pipeline and storage business, a coal
business and certain independent power producers (IPPs). In addition to the
following discussion, see Note 7 of our Notes to Consolidated Financial
Statements within this Form 10-Q.

Pushan Power Plant
------------------
In December 2003, we signed an agreement to sell our interest in the Pushan
Power Plant in Nanyang, China to our minority interest partner. The sale was
completed in March 2004 and the effect of the sale on our first quarter results
of operations was not significant.

Texas Generation
----------------
We made progress on our planned divestiture of certain Texas generation assets
by (1) announcing in January 2004 that we had signed an agreement to sell TCC's
7.81% share of the Oklaunion Power Station for approximately $43 million,
subject to closing adjustments, (2) announcing in February 2004 that we had
signed an agreement to sell TCC's 25.2% share of the South Texas Project nuclear
plant for approximately $333 million, subject to closing adjustments, and (3)
closing on the sale of TCC's remaining generation assets, including eight
natural gas plants, one coal-fired plant and one hydro plant for approximately
$425 million, net of adjustments. Subject to certain issues that have arisen
relating to co-owners' rights of first refusal, we expect the sales of TCC's
shares of Oklaunion and South Texas Project to close before the end of 2004.
There could, however, be potential delays in receiving necessary regulatory
approvals and clearances which may delay the closing. The sale of TCC's
remaining generation assets was completed in July 2004. We will file with the
PUCT to recover net stranded costs associated with each of the sales pursuant to
Texas restructuring legislation.

AEP Coal
--------
As a result of management's decision to exit our non-core businesses, we
retained an advisor in 2003 to facilitate the sale of AEP Coal. In March 2004,
an agreement was reached to sell assets, exclusive of certain reserves and
related liabilities, of the mining operations of AEP Coal. The sale closed in
April 2004 and the effect of the sale on second quarter 2004 results of
operations was not significant.

Gas Operations
--------------
During the third quarter of 2003, management hired advisors to review business
options regarding various investment components of our Investments-Gas
Operations segment. We continue to evaluate the merits of retaining or selling
our interest in Houston Pipe Line Company L.P., including the Bammel storage
facility, which is part of our Investments-Gas Operations segment. In February
2004, we signed an agreement to sell LIG Pipeline Company, which contained the
pipeline and processing assets of Louisiana Intrastate Gas (LIG). The sale was
completed in early April 2004 and the impact on results of operations in the
second quarter of 2004 was not significant. We continue to market Jefferson
Island Storage & Hub, L.L.C., the remaining LIG gas storage entity, and
anticipate the sale before the end of 2004.

IPP Investments
---------------
During the third quarter of 2003, we initiated an effort to sell four domestic
IPP investments. In accordance with accounting principles generally accepted in
the United States of America, we were required to measure the impairment of each
of these four investments individually. Based on studies using market
assumptions, which indicated that two of the facilities had declines in fair
value that were other than temporary in nature, we recorded an impairment of $70
million pre-tax ($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 planned sale of our interest in these IPPs.

In March 2004, we entered into an agreement to sell the four domestic IPP
investments for a sales price of $156 million, subject to closing adjustments.
An additional pre-tax impairment of $1.6 million was recorded in June 2004
(recorded in Maintenance and Other Operation expense) to decrease the carrying
value of the Colorado plant investments to their estimated sales price, less
selling expenses. We closed on the sale of the two Florida investments and the
Brush II plant in Colorado in July 2004, resulting in a pre-tax gain of
approximately $100 million, generated primarily from the sale of the two Florida
IPPs which were not originally impaired. The gain was recorded during July 2004.
The sale of the Ft. Lupton, Colorado plant is awaiting FERC approval and is
expected to close during the third quarter 2004, with no significant effect on
results of operations during the third quarter 2004.

UK Operations
-------------
In July 2004, we completed the sale of substantially all operations and assets
within our Investments - UK Operations segment for approximately $456 million.
The sale included Fiddler's Ferry, a coal-fired power plant in northwest
England, Ferrybridge, a coal-fired power plant in northeast England, related
coal assets, and a number of related commodities contracts. We are still
determining the final impact from the sale on our third quarter 2004 results of
operations. Although the final sales price will be subject to closing
adjustments, expected to be determined during the third quarter 2004, we
believe that a gain on sale, which would be included in discontinued operations,
may result.

Other
-----
We continue to have discussions with various parties on business alternatives
for certain of our other non-core investments, which may result in further
dispositions in the future.

The ultimate timing for a disposition of one or more of these assets will depend
upon market conditions and the value of any buyer's proposal. We believe our
non-core assets are stated at fair value. However, we may realize losses from
operations or losses or gains upon the eventual disposition of these assets
that, in the aggregate, could have a material impact on our results of
operations, cash flows and financial condition.

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

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

The status of the transfer of functional control of our subsidiaries'
transmission systems to RTOs or the status of our participation in RTOs has not
changed significantly from our disclosure as described in "RTO Formation" within
the "Management's Financial Discussion and Analysis of Results of Operations"
section of the 2003 Annual Report.

In November 2003, the FERC preliminarily found that we must fulfill our CSW
merger condition to join an RTO by integrating into PJM (transmission and
markets) by October 1, 2004. FERC based their order on PURPA 205(a), which
allows FERC to exempt electric utilities from state law or regulation in certain
circumstances. An ALJ held hearings on issues including whether the laws, rules,
or regulations of Virginia and Kentucky prevent us from joining an RTO and
whether the exceptions under PURPA 205(a) apply. The FERC ALJ affirmed the
FERC's preliminary findings in March 2004. The FERC issued a final order in June
2004.

In April 2004, we reached an agreement with interveners to settle the RTO issues
in Kentucky. The KPSC approved the settlement agreement in May 2004 and the FERC
approved the settlement in June 2004.

In July 2004, we reached an agreement with the intervenors to settle the RTO
issues in Virginia. The settlement agreement is now subject to approval by the
Virginia SCC.

If the Virginia settlement is approved, it should allow our AEP East companies
to join PJM and address state concerns without any significant expected adverse
impacts on future results of operations.

AEP West companies are members of ERCOT or SPP. In February 2004, the FERC
granted RTO status to the SPP, subject to fulfilling specified requirements.
Regulatory activities concerning various RTO issues are ongoing in Arkansas and
Louisiana.

Litigation
----------

We continue to be involved in various litigation matters as described in the
"Significant Factors - Litigation" section of Management's Financial Discussion
and Analysis of Results of Operations in our 2003 Annual Report. The 2003 Annual
Report should be read in conjunction with this report in order to understand
other litigation matters that did not have significant changes in status since
the issuance of our 2003 Annual Report, but may have a material impact on our
future results of operations, cash flows and financial condition. Other matters
described in the 2003 Annual Report that did not have significant changes during
the first six months of 2004, that should be read in order to gain a full
understanding of our current litigation include: (1) Bank of Montreal Claim, (2)
Shareholders' Litigation, (3) Cornerstone Lawsuit, and (4) Potential Uninsured
Losses.

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

See discussion of New Source Review Litigation within "Significant Factors -
Environmental Matters."

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

In 2002, certain of our subsidiaries filed claims against Enron and its
subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy
Court for the Southern District of New York. At the date of Enron's bankruptcy,
certain of our subsidiaries had open trading contracts and trading accounts
receivables and payables with Enron. In addition, on June 1, 2001, we purchased
HPL from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.

Bammel storage facility and HPL indemnification matters - In connection with the
2001 acquisition of HPL, we entered into a prepaid arrangement under which we
acquired exclusive rights to use and operate the underground Bammel gas storage
facility and appurtenant pipelines pursuant to an agreement with BAM Lease
Company. This exclusive right to use the referenced facility is for a term of 30
years, with a renewal right for another 20 years.

In January 2004, we filed an amended lawsuit against Enron and its subsidiaries
in the U.S. Bankruptcy Court claiming that Enron did not have the right to
reject the Bammel storage facility agreement or the cushion gas use agreement,
described below. In April 2004, AEP and Enron entered into a settlement
agreement under which we will acquire title to the Bammel gas storage facility
and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF)
of natural gas currently used as cushion gas for $115 million. AEP and Enron
will mutually release each other from all claims associated with the Bammel
facility, including our indemnity claims. The proposed settlement is subject to
Bankruptcy Court approval. The parties' respective trading claims and Bank of
America's (BOA) purported lien on approximately 55 BCF of natural gas in the
Bammel storage reservoir (as described below) are not covered by the settlement
agreement.

Right to use of cushion gas agreements - In connection with the 2001 acquisition
of HPL, we also entered into an agreement with BAM Lease Company, which grants
HPL the exclusive right to use approximately 65 BCF of cushion gas (the 10.5 BCF
and 55 BCF described in the preceding paragraph) required for the normal
operation of the Bammel gas storage facility. At the time of our acquisition of
HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an
agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the
time of our acquisition, Enron and the BOA Syndicate also released HPL from all
prior and future liabilities and obligations in connection with the financing
arrangement.

After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported
default by Enron under the terms of the financing arrangement. In July 2002, the
BOA Syndicate filed a lawsuit against HPL in the state court of Texas seeking a
declaratory judgment that the BOA Syndicate has a valid and enforceable security
interest in gas purportedly in the Bammel storage reservoir. In December 2003,
the Texas state court granted partial summary judgment in favor of the BOA
Syndicate. HPL appealed this decision. In June 2004, BOA filed an amended
petition in a separate lawsuit in Texas state court seeking to obtain possession
of up to 55 BCF of storage gas in the Bammel storage facility or its fair value.

In October 2003, AEP filed a lawsuit against BOA in the United States District
Court for the Southern District of Texas. BOA led a lending syndicate involving
the 1997 gas monetization that Enron and its subsidiaries undertook and the
leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit
asserts that BOA made misrepresentations and engaged in fraud to induce and
promote the stock sale of HPL, that BOA directly benefited from the sale of HPL
and that AEP undertook the stock purchase and entered into the Bammel storage
facility lease arrangement with Enron and the cushion gas arrangement with Enron
and BOA based on misrepresentations that BOA made about Enron's financial
condition that BOA knew or should have known were false including that the 1997
gas monetization did not contravene or constitute a default of any federal,
state, or local statute, rule, regulation, code or any law. In February 2004,
BOA filed a motion to dismiss this Texas federal lawsuit.

In February 2004, in connection with BOA's dispute, Enron filed Notices of
Rejection regarding the cushion gas exclusive right to use agreement and other
incidental agreements. We have objected to Enron's attempted rejection of these
agreements.

Commodity trading settlement disputes - In September 2003, Enron filed a
complaint in the Bankruptcy Court against AEPES challenging AEP's offsetting of
receivables and payables and related collateral across various Enron entities
and seeking payment of approximately $125 million plus interest in connection
with gas related trading transactions. AEP has asserted its right to offset
trading payables owed to various Enron entities against trading receivables due
to several AEP subsidiaries. The parties are currently in non-binding
court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC
seeking approximately $93 million plus interest in connection with a transaction
for the sale and purchase of physical power among Enron, AEP and Allegheny
Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the
effects of the transaction. AEP believes it has several defenses to the claims
in the action being brought by Enron. The parties are currently in non-binding
court-sponsored mediation.

Enron bankruptcy summary - The amount expensed in prior years in connection with
the Enron bankruptcy was based on an analysis of contracts where AEP and Enron
entities are counterparties, the offsetting of receivables and payables, the
application of deposits from Enron entities and management's analysis of the
HPL-related purchase contingencies and indemnifications. As noted above, Enron
has challenged our offsetting of receivables and payables and there is a dispute
regarding the cushion gas agreement. Management is unable to predict the outcome
of these lawsuits or their impact on our results of operations, cash flows or
financial condition.

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

Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider (REP),
filed a lawsuit in federal District Court in Corpus Christi, Texas, in July
2003, against us and four AEP subsidiaries, certain unaffiliated energy
companies and ERCOT. The action alleges violations of the Sherman Antitrust Act,
fraud, negligent misrepresentation, breach of fiduciary duty, breach of
contract, civil conspiracy and negligence. The allegations, not all of which are
made against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price spikes
requiring TCE to post additional collateral and ultimately forced it into
bankruptcy when it was unable to raise prices to its customers due to fixed
price contracts. The suit alleges over $500 million in damages for all
defendants and seeks recovery of damages, exemplary damages and court costs. Two
additional parties, Utility Choice, LLC and Cirro Energy Corporation, have
sought leave to intervene as plaintiffs asserting similar claims. We filed a
Motion to Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. We filed a Motion to Dismiss the amended complaint. In June 2004, the
Court dismissed all claims against the AEP companies. TCE has appealed the trial
court's decision to the United States Court of Appeals for the Fifth Circuit.

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

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

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. In January 2004, the CFTC issued a request for
documents and other information in connection with a CFTC investigation of
activities affecting the price of natural gas in the fall of 2003. We responded
to that request. The case is in the initial pleading stage with our response to
the complaint currently due on September 13, 2004. Although management is unable
to predict the outcome of this case, we recorded a provision in 2003 and the
action is not expected to have a material effect on future results of
operations, financial condition or cash flows. Management cannot predict whether
these governmental agencies will take further action with respect to these
matters.

SWEPCo Notice of Enforcement and Notice of Citizen Suit
-------------------------------------------------------

On July 13, 2004, two special interest groups issued a notice of intent to
commence a citizen suit under the Clean Air Act for alleged violations of
various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and
Pirkey plants. This notice was prompted by allegations made by a terminated AEP
employee. The allegations at the Welsh Plant concern compliance with emission
limitations on particulate matter and carbon monoxide, compliance with
a referenced design heat input valve, and compliance with certain reporting
requirements. The allegations at the Knox Lee Plant relate to the receipt of an
off-specification fuel oil, and the allegations at Pirkey Plant relate to
testing and reporting of volatile organic compound emissions. No action can be
commenced until 60 days after the date of notice.

On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a
Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary
of findings resulting from a compliance investigation at the plant. The summary
includes allegations concerning compliance with certain recordkeeping and
reporting requirements, compliance with a referenced design heat input valve in
the Welsh permit, compliance with a fuel sulfur content limit, and compliance
with emission limits for sulfur dioxide.

SWEPCo has previously reported to the TCEQ, deviations related to the receipt of
off-specification fuel at Knox Lee, and the referenced recordkeeping and
reporting requirements and heat input valve at Welsh. We are preparing
additional responses to the Notice of Enforcement and the notice from the
special interest groups. Management is unable to predict the timing of any
future action by TCEQ or the special interest groups or the effect of such
actions on results of operations, cash flows or financial condition.

Carbon Dioxide Public Nuisance Claims
-------------------------------------

On July 21, 2004, attorneys general from eight states and the corporation
counsel for the City of New York filed an action in federal district court for
the Southern District of New York against AEP, AEPSC and four other unaffiliated
governmental and investor-owned electric utility systems. That same day, a
similar complaint was filed in the same court against the same defendants by the
Natural Resources Defense Council on behalf of two special interest groups. The
actions allege that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts associated
with global warming, and seek injunctive relief in the form of specific emission
reduction commitments from the defendants. Management believes the actions are
without merit and intends to vigorously defend against the claims.

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

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

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

As discussed in our 2003 Annual Report, there are emerging environmental control
requirements that we expect will result in substantial capital investments and
operational costs. The sources of these future requirements include:

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

This discussion updates certain events occurring in 2004. You should also read
the "Significant Factors - Environmental Matters" section within Management's
Financial Discussion and Analysis of Results of Operations in our 2003 Annual
Report for a description of all material environmental matters affecting us,
including, but not limited to, (1) the current air quality regulatory framework,
(2) estimated air quality environmental investments, (3) Superfund and state
remediation, (4) global climate change, and (5) costs for spent nuclear fuel
disposal and decommissioning.

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

In 1997, the Federal EPA adopted new, more stringent national ambient air
quality standards for fine particulate matter and ground-level ozone. The
Federal EPA is in the process of developing final designations for fine
particulate matter non-attainment areas. The Federal EPA finalized designations
for ozone non-attainment areas on April 15, 2004. On the same day, the
Administrator of the Federal EPA signed a final rule establishing the elements
that must be included in state implementation plans (SIPs) to achieve the new
standards, and setting deadlines ranging from 2008 to 2015 for achieving
compliance with the final standard, based on the severity of non-attainment. All
or parts of 474 counties are affected by this new rule, including many urban
areas in the Eastern United States.

The Federal EPA identified SO2 and NOx emissions as precursors to the formation
of fine particulate matter. NOx emissions are also identified as a precursor to
the formation of ground-level ozone. As a result, requirements for future
reductions in emissions of NOx and SO2 from our generating units are highly
probable. In addition, the Federal EPA proposed a set of options for future
mercury controls at coal-fired power plants.

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

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

 o  The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce
    SO2 and NOx emissions across the eastern half of the United States (29
    states and the District of Columbia) and make progress toward attainment
    of the new fine particulate matter and ground-level ozone national ambient
    air quality standards. These reductions could also satisfy these states'
    obligations to make reasonable progress towards the national visibility
    goal under the regional haze program.
 o  The Federal EPA proposed to regulate mercury emissions from coal-fired
    electric generating units.

The CAIR would require affected states to include, in their SIPs, a program to
reduce NOx and SO2 emissions from coal-fired electric utility units. SO2 and NOx
emissions would be reduced in two phases, which would be implemented through a
cap-and-trade program. Regional SO2 emissions would be reduced to 3.9 million
tons by 2010 and to 2.7 million tons by 2015. Regional NOx emissions would be
reduced to 1.6 million tons by 2010 and to 1.3 million tons by 2015. Rules to
implement the SO2 and NOx trading programs were proposed on June 10, 2004.

On April 15, 2004, the Federal EPA Administrator signed a proposed rule
detailing how states should analyze and include "Best Available Retrofit"
requirements for individual facilities in their SIPs to address regional haze.
The guidance applies to facilities built between 1962 and 1977 that emit more
than 250 tons per year of certain regulated pollutants in specific industrial
categories, including utility boilers. The Federal EPA included an alternative
"Best Available Retrofit" program based on emissions budgeting and trading
programs. For utility units that are affected by the CAIR, described above, the
Federal EPA proposed that participation in the trading program under the CAIR
would satisfy any applicable "Best Available Retrofit" requirements. However,
the guidance preserves the ability of a state to require site-specific
installation of pollution control equipment through the SIP for purposes of
abating regional haze.

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

The Federal EPA recommends, and we support, a second mercury emission reduction
option. The second option would permit mercury emission reductions to be
achieved from existing sources through a national cap-and-trade approach. The
cap-and-trade approach would include a two-phase mercury reduction program for
coal-fired utilities. This approach would coordinate the reduction requirements
for mercury with the SO2 and NOx reduction requirements imposed on the same
sources under the CAIR. Coordination is significantly more cost-effective
because technologies like scrubbers and SCRs, which can be used to comply with
the more stringent SO2 and NOx requirements, have also proven effective in
reducing mercury emissions on certain coal-fired units that burn bituminous
coal. The second option contemplates reducing mercury emissions from 48 tons to
34 tons by 2010 and to 15 tons by 2018. A supplemental proposal including
unit-specific allocations and a framework for the emissions budgeting and
trading program preferred by the Federal EPA was published in the Federal
Register on March 16, 2004. We filed comments on both the initial proposal and
the supplemental notice in June 2004.

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

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

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

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

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

On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to
"perfect" its complaint in the pending litigation. The NOV expands the number of
alleged "modifications" undertaken at the Amos, Cardinal, Conesville, Kammer,
Muskingum River, Sporn and Tanners Creek plants during scheduled outages on
these units from 1979 through the present. Approximately one-third of the
allegations in the NOV are already contained in allegations made by the states
or the special interest groups in the pending litigation. The Federal EPA is
expected to file a motion to amend its complaint, and, to the extent that motion
seeks to expand the scope of the pending litigation, the AEP subsidiaries will
oppose that motion.

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

In other pending CAA litigation against unaffiliated utility companies
referenced in the annual report, the petition for certiorari filed with the
Supreme Court in the TVA litigation was denied by the Court on May 3, 2004. In
addition, the United States has filed a notice of appeal with the Fourth Circuit
Court of Appeals from the adverse decision in the Duke case, and a briefing
order has been issued by the Court that will require briefing to be completed by
late September 2004.

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

On July 9, 2004, the Federal EPA published in the Federal Register a rule
pursuant to the Clean Water Act that will require all large existing,
once-through cooled power plants to meet certain performance standards to reduce
the mortality of juvenile and adult fish or other larger organisms pinned
against a plant's cooling water intake screens. All plants must reduce fish
mortality by 80% to 95%. A subset of these plants that are located on sensitive
water bodies will be required to meet additional performance standards for
reducing the number of smaller organisms passing through the water screens and
the cooling system. These plants must reduce the rate of smaller organisms
passing through the plant by 60% to 90%. Sensitive water bodies are defined as
oceans, estuaries, the Great Lakes, and small rivers with large plants. These
rules will result in additional capital and operation and maintenance expenses
to ensure compliance. The estimated capital cost of compliance for our
facilities, based on the Federal EPA's analysis in the rule, is $193 million.
Any capital costs associated with compliance activities to meet the new
performance standards would likely be incurred during the years 2008 through
2010. We have not independently confirmed the accuracy of the Federal EPA's
estimate. The rule has provisions to limit compliance costs. We may propose less
costly site-specific performance criteria if our compliance cost estimates are
significantly greater than the Federal EPA's estimates or greater than the
environmental benefits. The rule also allows us to propose mitigation (also
called restoration measures) that is less costly and has equivalent or superior
environmental benefits than meeting the criteria in whole or in part. Several
states, electric utilities (including our APCo subsidiary) and environmental
groups appealed certain aspects of the rule. We cannot predict the outcome of
the appeals.

Spent Nuclear Fuel Disposal
---------------------------

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

Nuclear Decommissioning
-----------------------

As discussed in the 2003 Annual Report, decommissioning costs are accrued over
the service life of STP. The licenses to operate the two nuclear units at STP
expire in 2027 and 2028. TCC had estimated its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of approximately $8 million per year.

In May 2004, an updated decommissioning study was completed for STP. The study
estimates TCC's share of the decommissioning costs of STP to be $344 million in
nondiscounted 2004 dollars. TCC is in the process of selling its ownership
interest in STP to a non-affiliate, and upon completion of the sale it is
anticipated that TCC will no longer be obligated for nuclear decommissioning
liabilities associated with STP.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Management's Financial Discussion and
Analysis of Results of Operations" in the 2003 Annual Report 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.

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

As discussed in our 2003 Annual Report, there are several "Other Matters"
affecting us, including FERC's proposed standard market design and FERC's market
power mitigation efforts. These were no significant changes to the status of
FERC's proposed standard market design. The current status of FERC's market
power mitigation efforts is described below.

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

A FERC order issued in November 2001 on AEP's triennial market based wholesale
power rate authorization update required certain mitigation actions that AEP
would need to take for sales/purchases within its control area and required AEP
to post information on its website regarding its power system's status. As a
result of a request for rehearing filed by AEP and other market participants,
FERC issued an order delaying the effective date of the mitigation plan until
after a planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. In April 2004, the FERC issued two orders concerning
utilities' ability to sell wholesale electricity at market based rates. In the
first order, the FERC adopted two new interim screens for assessing potential
generation market power of applicants for wholesale market based rates, and
described additional analyses and mitigation measures that could be presented if
an applicant does not pass one of these interim screens. In July 2004, the FERC
issued an order on rehearing affirming its conclusions in the April order and
directing AEP and two unaffiliated utilities to file generation market power
analyses within 30 days. In the second order, the FERC initiated a rulemaking to
consider whether the FERC's current methodology for determining whether a public
utility should be allowed to sell wholesale electricity at market-based rates
should be modified in any way. We plan to present evidence to demonstrate that
we do not possess market power in geographic areas where we sell wholesale
power.

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

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

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

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

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

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

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

<TABLE>
<CAPTION>

                                         MTM Risk Management Contract Net Assets (Liabilities)
                                                     Six Months Ended June 30, 2004

                                                                         Investments      Investments
                                                             Utility         Gas               UK
                                                           Operations     Operations     Operations (i)        Consolidated
                                                           ----------    -----------     --------------        ------------
                                                                                 (in millions)
<C>                                                            <C>             <C>             <C>                 <C>
Total MTM Risk Management Contract Net Assets
 (Liabilities) at December 31, 2003                            $286              $5            $(246)               $45
(Gain) Loss from Contracts Realized/Settled
  During the Period (a)                                         (77)              -              243                166
Fair Value of New Contracts When Entered
  Into During the Period (b)                                      -               -                -                  -
Net Option Premiums Paid/(Received) (c)                           8              14                1                 23
Change in Fair Value Due to Valuation Methodology
 Changes (d)                                                      3               -                -                  3
Changes in Fair Value of Risk Management
  Contracts (e)                                                  48             (45)             (30)               (27)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (f)                         (1)              -               -                  (1)
                                                               -----           -----           ------              -----
Total MTM Risk Management Contract Net Assets
 (Liabilities) at June 30, 2004                                $267            $(26)            $(32)               209
                                                               =====           =====           ======
Net Cash Flow Hedge Contracts (g)                                                                                   (31)
Net Risk Management Liabilities
 Held for Sale, included in the totals above (h)                                                                     18
                                                                                                                   -----
Ending Net Risk Management Assets at June 30, 2004                                                                 $196
                                                                                                                   =====

</TABLE>


(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
    includes realized risk management contracts and related derivatives
    that settled during 2004 and were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
    Period" represents the fair value at inception of long-term
    contracts entered into with customers during 2004. Most of the fair
    value comes from longer term fixed price contracts with customers
    that seek to limit their risk against fluctuating energy prices. The
    contract prices are valued against market curves associated with the
    delivery location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
    premiums paid/(received) as they relate to unexercised and unexpired
    option contracts entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
    represents the impact of AEP changes in methodology in regards to
    credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
    fair value change in the risk management portfolio due to market
    fluctuations during the current period. Market fluctuations are
    attributable to various factors such as supply/demand, weather,
    storage, etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
    Regulated Jurisdictions" relates to the net gains (losses) of those
    contracts that are not reflected in the Consolidated Statements of
    Operations. These net gains (losses) are recorded as regulatory
    liabilities/assets for those subsidiaries that operate in regulated
    jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed in detail
    within the following pages.
(h) See Note 7 for discussion of Assets Held for Sale.
(i) During 2004, we began to unwind our risk management contracts
    within the U.K. as part of our planned divestiture of our UK Operations.
    We completed the sale of substantially all of our operations and
    assets in the Investments-UK Operations segment in July 2004.

<TABLE>
<CAPTION>


                               Detail on MTM Risk Management Contract Net Assets (Liabilities)
                                                    As of June 30, 2004

                                                                  Investments       Investments
                                                   Utility            Gas               UK
                                                  Operations       Operations        Operations     Consolidated
                                                  ----------      -----------       -----------     ------------
                                                                          (in millions)
<C>                                                  <C>              <C>             <C>              <C>
Current Assets                                        $560             $229            $194               $983
Non Current Assets                                     368              153              56                577
                                                     ------           ------          ------           --------
Total Assets                                          $928             $382             $250            $1,560
                                                     ------           ------          ------           --------

Current Liabilities                                  $(451)           $(239)          $(233)             $(923)
Non Current Liabilities                               (210)            (169)            (49)              (428)
                                                     ------           ------          ------           --------
Total Liabilities                                    $(661)           $(408)          $(282)           $(1,351)
                                                     ------           ------          ------           --------

Total Net Assets (Liabilities),
  excluding Cash Flow Hedges                          $267             $(26)           $(32)              $209
                                                     ======           ======          ======           ========

</TABLE>

<TABLE>
<CAPTION>

                                   Reconciliation of MTM Risk Management Contracts to
                                              Consolidated Balance Sheets
                                                 As of June 30, 2004

                                                    Risk
                                                  Management         Cash Flow          Assets Held
                                                  Contracts*          Hedges             for Sale           Consolidated
                                                  ----------         ---------          -----------         ------------
                                                                             (in millions)
<C>                                                <C>                 <C>                 <C>               <C>
Current Assets                                        $983               $82               $(251)               $814
Non Current Assets                                     577                 6                 (56)                527
                                                   --------            ------              ------            --------
Total Assets                                        $1,560               $88               $(307)             $1,341
                                                   --------            ------              ------            --------

Current Liabilities                                  $(923)            $(105)               $276               $(752)
Non Current Liabilities                               (428)              (14)                 49                (393)
                                                   --------            ------              ------            --------
Total Liabilities                                  $(1,351)            $(119)               $325             $(1,145)
                                                   --------            ------              ------            --------

Total Net Assets (Liabilities)                        $209              $(31)                $18                $196
                                                   ========            ======              ======            ========
</TABLE>


*Excluding Cash Flow Hedges.

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

<TABLE>
<CAPTION>

                               Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities)
                                                      Fair Value of Contracts as of June 30, 2004

                                     Remainder                                                                After
                                       2004           2005         2006          2007         2008            2008        Total (c)
                                     ---------        ----         ----          ----         ----            -----       ---------
                                                                            (in millions)

<C>                                     <C>           <C>          <C>           <C>          <C>             <C>           <C>
Utility Operations:
Prices Actively Quoted - Exchange
 Traded Contracts                       $(28)         $(32)          $1           $4           $-              $-           $(55)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)          88            44           12            7            3               -            154
Prices Based on Models and Other
 Valuation Methods (b)                     7            55           14           27           20              45            168
                                        -----         -----        -----         ----         ----            ----          -----
Total                                    $67           $67          $27          $38          $23             $45           $267
                                        -----         -----        -----         ----         ----            ----          -----

Investments - Gas Operations:
Prices Actively Quoted - Exchange
 Traded Contracts                        $36           $42          $(2)          $1           $-              $-            $77
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)         (51)           14            -            -            -               -            (37)
Prices Based on Models and Other
 Valuation Methods (b)                     1           (48)          (8)          (3)          (3)             (5)           (66)
                                        -----         -----        -----         ----         ----            ----          -----
Total                                   $(14)           $8         $(10)         $(2)         $(3)            $(5)          $(26)
                                        -----         -----        -----         ----         ----            ----          -----

Investments - UK Operations:
Prices Actively Quoted - Exchange
 Traded Contracts                         $-            $-           $-           $-           $-              $-             $-
Prices Provided by Other External
  Sources - OTC Broker Quotes (a)         (4)          (31)           6            -            -               -            (29)
Prices Based on Models and Other
 Valuation Methods (b)                    (3)            -            -            -            -               -             (3)
                                        -----         -----        -----         ----         ----            ----          -----
Total                                    $(7)         $(31)          $6           $-           $-              $-           $(32)
                                        -----         -----        -----         ----         ----            ----          -----

Consolidated:
Prices Actively Quoted - Exchange
 Traded Contracts                         $8           $10          $(1)          $5           $-              $-            $22
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)          33            27           18            7            3               -             88
Prices Based on Models and Other
 Valuation Methods (b)                     5             7            6           24           17              40             99
                                        -----         -----        -----         ----         ----            ----          -----
Total                                    $46           $44          $23          $36          $20             $40           $209
                                        =====         =====        =====         ====         ====            ====          =====

</TABLE>

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

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

<TABLE>
<CAPTION>

                                Maximum Tenor of the Liquid Portion of Risk Management Contracts
                                                       As of June 30, 2004

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


        <C>                 <C>                                  <C>                                             <C>
        Natural Gas         Futures                              NYMEX Henry Hub                                 66
                            Physical Forwards                    Gulf Coast, Texas                               18
                            Swaps                                Gas East - Northeast, Mid-continent
                                                                   Gulf Coast, Texas                             18
                            Swaps                                Gas West - Rocky Mountains,
                                                                   West Coast                                    18
                            Exchange Option Volatility           NYMEX/Henry Hub                                 12

        Power               Futures                              PJM                                             30
                            Physical Forwards                    Cinergy                                         42
                            Physical Forwards                    PJM                                             42
                            Physical Forwards                    NYPP                                            30
                            Physical Forwards                    NEPOOL                                          18
                            Physical Forwards                    ERCOT                                           18
                            Physical Forwards                    TVA                                              -
                            Physical Forwards                    Com Ed                                          18
                            Physical Forwards                    Entergy                                          8
                            Physical Forwards                    PV, NP15, SP15, MidC, Mead                      54
                            Peak Power Volatility (Options)      Cinergy                                         12
                            Peak Power Volatility (Options)      PJM                                             12

        Crude Oil           Swaps                                West Texas Intermediate                         30

        Emissions           Credits                              SO2                                             30

        Coal                Physical Forwards                    PRB, NYMEX, CSX                                 30

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

        Power               Forwards and Options                 United Kingdom                                  24

        Coal                Forward Purchases and Sales          United Kingdom                                  15
                            Swaps                                Europe                                          36

        Freight             Swaps                                Europe                                          24


</TABLE>

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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. International subsidiaries use currency swaps to hedge exchange rate
fluctuations of debt denominated in foreign currencies. We do not hedge all
foreign currency exposure.

The tables below provide detail on effective cash flow hedges under SFAS 133
included in our balance sheet. The data in the first table will indicate the
magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts
designated as cash flow hedges are recorded in AOCI, therefore, economic hedge
contracts which are not designated as cash flow hedges are required to be
marked-to-market and are included in the previous risk management tables. This
table further indicates what portions of these hedges are expected to be
reclassified into net income in the next 12 months. The second table provides
the nature of changes from December 31, 2003 to June 30, 2004.

Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities. In accordance with accounting
principles generally accepted in the United States of America, all amounts are
presented net of related income taxes.

<TABLE>
<CAPTION>

                                Cash Flow Hedges included in Accumulated Other Comprehensive Loss
                                           On the Balance Sheet as of June 30, 2004

                                                                                          Portion Expected to
                                                           Accumulated Other be             Reclassified to
                                                              Comprehensive               Earnings During the
                                                            Loss After Tax (a)             Next 12 Months (b)
                                                           --------------------           -------------------
                                                                              (in millions)
        <C>                                                        <C>                           <C>
        Power, Gas and Coal                                         $(4)                           $-
        Foreign Currency                                            (10)                           (9)
        Interest Rate                                                (5)                           (3)
                                                                   -----                         -----

        Total                                                      $(19)                         $(12)
                                                                   =====                         =====

</TABLE>
<TABLE>
<CAPTION>

                                      Total Accumulated Other Comprehensive Income (Loss) Activity
                                                      Six Months Ended June 30, 2004

                                                       Power, Gas      Foreign
                                                        and Coal       Currency      Interest Rate    Consolidated
                                                       ----------      --------      -------------    ------------
                                                                             (in millions)
        <C>                                               <C>            <C>              <C>             <C>
        Beginning Balance,
         December 31, 2003                                $(65)          $(20)            $(9)            $(94)
        Changes in Fair Value (c)                            5             (4)              -                1
        Reclassifications from AOCI to Net
         Income (d)                                         56             14               4               74
                                                          -----          -----            ----            -----
        Ending Balance,
         June 30, 2004                                     $(4)          $(10)            $(5)            $(19)
                                                          =====          =====            ====            =====

</TABLE>

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

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

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

We have risk management contracts with numerous counterparties. Since open risk
management contracts are valued based on changes in market prices of the related
commodities, our exposures change daily. Except for one counterparty who has a
net exposure of approximately $44 million, we believe that credit exposure with
any one counterparty is not material to our financial condition at June 30,
2004. At June 30, 2004, our credit exposure net of credit collateral to sub
investment grade counterparties was approximately 21% expressed in terms of net
MTM assets and net receivables. The concentration in non-investment grade credit
quality was largely due to coal exposures related to financially weak domestic
coal counterparties and coal and freight exposures related to our U.K.
investments. These exposures were driven by the continued high levels of prices
for coal and freight. As of June 30, 2004, the following table approximates our
counterparty credit quality and exposure based on netting across commodities and
instruments:

<TABLE>
<CAPTION>

                                                                                            Number of          Net Exposure of
Counterparty                     Exposure Before         Credit            Net            Counterparties        Counterparties
Credit Quality                   Credit Collateral     Collateral       Exposure               > 10%                > 10%
--------------                   -----------------     ----------       --------          --------------       ---------------
                                                    (in millions, except number of counterparties)

<C>                                 <C>                   <C>           <C>                     <C>                  <C>
Investment Grade                      $877                $138            $739                  1                     $75
Split Rating                            24                   2              22                  2                      20
Non-Investment Grade                   325                 171             154                  3                      94
No External Ratings:
  Internal Investment
    Grade                              345                   9             336                  1                      58
  Internal Non-Investment
    Grade                              176                  41             135                  2                      43
                                    -------               -----         -------                 -                    -----
Total                               $1,747                $361          $1,386                  9                    $290
                                    =======               =====         =======                 =                    =====

</TABLE>

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

This table provides information on operating measures regarding the proportion
of output of our generation facilities (based on economic availability
projections) economically hedged, including both contracts designated as cash
flow hedges under SFAS 133 and contracts not designated as cash flow hedges.
This information is forward-looking and provided on a prospective basis through
December 31, 2006. Please note that this table is a point-in-time estimate,
subject to changes in market conditions and our decisions on how to manage
operations and risk. "Estimated Plant Output Hedged," represents the portion of
megawatthours of future generation/production for which we have sales
commitments or estimated requirement obligations to customers.

                      Generation Plant Hedging Information
                           Estimated Next Three Years
                               As of June 30, 2004

                                            Remainder
                                               2004       2005        2006
                                               ----       ----        ----
Estimated Plant Output Hedged                   90%        89%         87%


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

We use a risk measurement model, which calculates Value at Risk (VaR) to measure
our commodity price risk in the risk management portfolio. The VaR is based on
the variance-covariance method using historical prices to estimate volatilities
and correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at June 30, 2004, a near term typical change
in commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.

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

                               VaR Model

       Six Months Ended                     Twelve Months Ended
         June 30, 2004                       December 31, 2003
   -----------------------                -----------------------
        (in millions)                           (in millions)
   End  High  Average  Low                End  High  Average  Low
   ---  ----  -------  ---                ---  ----  -------  ---
    $3  $19     $7      $2                $11   $19    $7      $4

The 2004 High VaR was due to the wind-down of the London risk management
activities. These activities were concluded in March 2004. The 2004 High VaR,
excluding London activities, was approximately $8 million.

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


<TABLE>
<CAPTION>

                                                      CCRO VaR Metrics

                                                         Average for
                                                         Year-to-Date         High for               Low for
                                         June 30, 2004      2004          Year-to-Date  2004     Year-to-Date 2004
                                         -------------   ------------     ------------------     -----------------
                                                                 (in millions)
<C>                                          <C>             <C>                <C>                     <C>
95% Confidence Level, Ten-Day
  Holding Period                             $13             $26                $73                     $7

99% Confidence Level, One-Day
  Holding Period                              $5             $11                $30                     $3

</TABLE>

We utilize a VaR model to measure interest rate market risk exposure. The
interest rate VaR model is based on a Monte Carlo simulation with a 95%
confidence level and a one-year holding period. The volatilities and
correlations were based on three years of daily prices. The risk of potential
loss in fair value attributable to our exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $903 million at June
30, 2004 and $1.013 billion at December 31, 2003. We would not expect to
liquidate our entire debt portfolio in a one-year holding period, therefore a
near term change in interest rates should not materially affect our results of
operations, cash flows or consolidated financial position.

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

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


                                 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                             CONSOLIDATED STATEMENTS OF OPERATIONS
                                   For the Three and Six Months Ended June 30, 2004 and 2003
                                            (in millions, except per-share amounts)
                                                       (Unaudited)

                                                                    Three Months Ended                      Six Months Ended
                                                                 ------------------------                --------------------
                                                                 2004                2003                2004            2003
                                                                 ----                ----                ----            ----
<C>                                                              <C>                <C>                 <C>             <C>
                   REVENUES
------------------------------------------------------
Utility Operations                                               $2,501             $2,672              $5,080          $5,359
Gas Operations                                                      777                638               1,429           1,571
Other                                                                90                140                 200             305
                                                                 -------            -------             -------         -------
TOTAL                                                             3,368              3,450               6,709           7,235
                                                                 -------            -------             -------         -------
                   EXPENSES
------------------------------------------------------
Fuel for Electric Generation                                        734                759               1,428           1,492
Purchased Electricity for Resale                                     87                214                 170             370
Purchased Gas for Resale                                            701                650               1,286           1,528
Maintenance and Other Operation                                     972                946               1,836           1,835
Depreciation and Amortization                                       320                331                 639             642
Taxes Other Than Income Taxes                                       176                157                 360             345
                                                                 -------            -------             -------         -------
TOTAL                                                             2,990              3,057               5,719           6,212
                                                                 -------            -------             -------         -------

OPERATING INCOME                                                    378                393                 990           1,023
                                                                 -------            -------             -------         -------

Other Income (Expense), Net                                          51                 50                  91             116
                                                                 -------            -------             -------         -------

        INTEREST AND OTHER CAPITAL CHARGES
------------------------------------------------------
Interest                                                            199                197                 398             389
Preferred Stock Dividend Requirements of Subsidiaries                 1                  3                   3               6
Minority Interest in Finance Subsidiary                               -                  8                   -              17
                                                                 -------            -------             -------         -------
TOTAL                                                               200                208                 401             412
                                                                 -------            -------             -------         -------

INCOME BEFORE INCOME TAXES                                          229                235                 680             727
Income Taxes                                                         78                 58                 240             257
                                                                 -------            -------             -------         -------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE
 EFFECT OF ACCOUNTING CHANGES                                       151                177                 440             470

DISCONTINUED OPERATIONS (Net of Tax)                                (51)                (2)                (58)            (48)

 CUMULATIVE EFFECT OF ACCOUNTING CHANGES (Net of Tax)
------------------------------------------------------
Accounting for Risk Management Contracts                              -                  -                   -             (49)
Asset Retirement Obligations                                          -                  -                   -             242
                                                                 -------            -------             -------         -------
NET INCOME                                                         $100               $175                $382            $615
                                                                 =======            =======             =======         =======

AVERAGE NUMBER OF SHARES OUTSTANDING                                396                395                 396             376
                                                                 =======            =======             =======         =======

               EARNINGS PER SHARE
------------------------------------------------------
Income Before Discontinued Operations and Cumulative
  Effect of Accounting Changes                                    $0.38              $0.45               $1.11           $1.25
Discontinued Operations                                           (0.13)             (0.01)              (0.15)          (0.12)
Cumulative Effect of Accounting Changes                               -                  -                   -            0.51
                                                                 -------            -------             -------         -------
TOTAL EARNINGS PER SHARE (BASIC AND DILUTED)                      $0.25              $0.44               $0.96           $1.64
                                                                 =======            =======             =======         =======

CASH DIVIDENDS PAID PER SHARE                                     $0.35              $0.35               $0.70           $0.95
                                                                 =======            =======             =======         =======

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


                                AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                 CONSOLIDATED BALANCE SHEETS
                                                          ASSETS
                                             June 30, 2004 and December 31, 2003
                                                        (Unaudited)

                                                                                              2004                 2003
                                                                                              ----                 ----
                                                                                                    (in millions)

<C>                                                                                         <C>                  <C>
               CURRENT ASSETS
----------------------------------------------------
Cash and Cash Equivalents                                                                      $858                 $976
Other Cash Deposits                                                                             208                  206
Accounts Receivable:
   Customers                                                                                  1,044                1,155
   Accrued Unbilled Revenues                                                                    560                  596
   Miscellaneous                                                                                 75                   83
   Allowance for Uncollectible Accounts                                                        (133)                (124)
                                                                                            --------             --------
   Total Receivables                                                                          1,546                1,710
                                                                                            --------             --------
Fuel, Materials and Supplies                                                                  1,192                  991
Risk Management Assets                                                                          814                  766
Margin Deposits                                                                                 128                  119
Other                                                                                           119                  129
                                                                                            --------             --------
TOTAL                                                                                         4,865                4,897
                                                                                            --------             --------

         PROPERTY, PLANT AND EQUIPMENT
----------------------------------------------------
Electric:
   Production                                                                                15,663               15,112
   Transmission                                                                               6,223                6,130
   Distribution                                                                              10,078                9,902
Other (including gas, coal mining and nuclear fuel)                                           3,613                3,572
Construction Work in Progress                                                                   967                1,305
                                                                                            --------             --------
TOTAL                                                                                        36,544               36,021
Less: Accumulated Depreciation and Amortization                                              14,363               14,004
                                                                                            --------             --------
TOTAL-NET                                                                                    22,181               22,017
                                                                                            --------             --------

           OTHER NON-CURRENT ASSETS
----------------------------------------------------
Regulatory Assets                                                                             3,521                3,548
Securitized Transition Assets                                                                   670                  689
Spent Nuclear Fuel and Decommissioning Trusts                                                 1,013                  982
Investments in Power and Distribution Projects                                                  214                  212
Goodwill                                                                                         78                   78
Long-term Risk Management Assets                                                                527                  494
Other                                                                                           724                  733
                                                                                            --------             --------
TOTAL                                                                                         6,747                6,736
                                                                                            --------             --------

Assets Held for Sale                                                                          2,055                2,761
Assets of Discontinued Operations                                                                 -                  333

TOTAL ASSETS                                                                                $35,848              $36,744
                                                                                            ========             ========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                          CONSOLIDATED BALANCE SHEETS
                                                      LIABILITIES AND SHAREHOLDERS' EQUITY
                                                      June 30, 2004 and December 31, 2003
                                                                 (Unaudited)

                                                                                                   2004                  2003
                                                                                                   ----                  ----
                                                                                                         (in millions)

<C>                                                                                             <C>                    <C>
                             CURRENT LIABILITIES
---------------------------------------------------------------------------------
Accounts Payable                                                                                 $1,165                 $1,337
Short-term Debt                                                                                     596                    326
Long-term Debt Due Within One Year*                                                               1,865                  1,779
Risk Management Liabilities                                                                         752                    631
Accrued Taxes                                                                                       762                    620
Accrued Interest                                                                                    199                    207
Customer Deposits                                                                                   462                    379
Other                                                                                               627                    703
                                                                                                --------               --------
TOTAL                                                                                             6,428                  5,982
                                                                                                --------               --------

                           NON-CURRENT LIABILITIES
---------------------------------------------------------------------------------
Long-term Debt*                                                                                  11,533                 12,322
Long-term Risk Management Liabilities                                                               393                    335
Deferred Income Taxes                                                                             4,144                  3,957
Regulatory Liabilities and Deferred Investment Tax Credits                                        2,277                  2,259
Asset Retirement Obligations and Nuclear Decommissioning                                            693                    651
Employee Benefits and Pension Obligations                                                           676                    667
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2                                         171                    176
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption                          72                     76
Deferred Credits and Other                                                                          542                    508
                                                                                                --------               --------
TOTAL                                                                                            20,501                 20,951
                                                                                                --------               --------

Liabilities Held for Sale                                                                           775                  1,710
Liabilities of Discontinued Operations                                                                -                    166

TOTAL LIABILITIES                                                                                27,704                 28,809
                                                                                                --------               --------

Cumulative Preferred Stocks of Subsidiaries not Subject to Mandatory Redemption                      61                     61

Commitments and Contingencies

                      COMMON SHAREHOLDERS' EQUITY
---------------------------------------------------------------------------------
Common Stock-Par Value $6.50:
                                          2004          2003
                                          ----          ----
Shares Authorized. . . . . . . . . . .600,000,000   600,000,000
Shares Issued. . . . . . . . . . . . .404,657,511   404,016,413
  (8,999,992 shares were held in treasury at June 30, 2004 and December 31, 2003)                 2,630                  2,626
Paid-in Capital                                                                                   4,193                  4,184
Retained Earnings                                                                                 1,595                  1,490
Accumulated Other Comprehensive Income (Loss)                                                      (335)                  (426)
                                                                                                --------               --------
TOTAL                                                                                             8,083                  7,874
                                                                                                --------               --------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                                      $35,848                $36,744
                                                                                                ========               ========

* See Accompanying Schedule

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                  CONSOLIDATED STATEMENTS OF CASH FLOWS
                                            For the Six Months Ended June 30, 2004 and 2003
                                                            (Unaudited)

                                                                                                     2004              2003
                                                                                                     ----              ----
                                                                                                          (in millions)
<C>                                                                                                 <C>               <C>
                   OPERATING ACTIVITIES
------------------------------------------------------
Net Income                                                                                           $382               $615
Plus:  Discontinued Operations                                                                         58                 48
                                                                                                    ------            -------
Income from Continuing Operations                                                                     440                663
Adjustments for Noncash Items:
    Depreciation and Amortization                                                                     639                642
    Deferred Income Taxes                                                                              92                 42
    Deferred Investment Tax Credits                                                                   (13)               (16)
    Cumulative Effect of Accounting Changes                                                             -               (193)
    Amortization of Deferred Property Taxes                                                            (2)                 -
    Amortization of Cook Plant Restart Costs                                                            -                 20
    Mark-to-Market of Risk Management Contracts                                                        50                (33)
Over/Under Fuel Recovery                                                                               (4)                85
Change in Other Non-Current Assets                                                                     38                (94)
Change in Other Non-Current Liabilities                                                                90                (13)
Changes in Certain Components of Working Capital:
    Accounts Receivable, Net                                                                          167                 (9)
    Accounts Payable                                                                                 (180)              (136)
    Fuel, Materials and Supplies                                                                     (196)               (40)
    Customer Deposits and Risk Management Collateral                                                   83                167
    Taxes Accrued                                                                                     140                 62
    Interest Accrued                                                                                   (8)               (16)
    Other Current Assets                                                                               (1)               (60)
    Other Current Liabilities                                                                         (73)              (221)
                                                                                                    ------            -------
Net Cash Flows From Operating Activities                                                            1,262                850
                                                                                                    ------            -------
                   INVESTING ACTIVITIES
------------------------------------------------------
Construction Expenditures                                                                            (697)              (639)
Change in Other Cash Deposits, Net                                                                     (2)                23
Investment in Discontinued Operations, Net                                                              -               (716)
Proceeds from Sale of Assets                                                                          131                 41
Other                                                                                                  (7)                 3
                                                                                                    ------            -------
Net Cash Flows Used For Investing Activities                                                         (575)            (1,288)
                                                                                                    ------            -------

                   FINANCING ACTIVITIES
------------------------------------------------------
Issuance of Common Stock                                                                               11              1,142
Issuance of Long-term Debt                                                                            263              3,472
Change in Short-term Debt, Net                                                                        188             (2,218)
Retirement of Long-term Debt                                                                         (986)            (1,407)
Retirement of Preferred Stock                                                                          (4)                (2)
Retirement of Minority Interest                                                                         -               (225)
Dividends Paid on Common Stock                                                                       (277)              (342)
                                                                                                    ------            -------
Net Cash Flows From (Used For) Financing Activities                                                  (805)               420
                                                                                                    ------            -------

Net Decrease in Cash and Cash Equivalents                                                            (118)               (18)
Cash and Cash Equivalents at Beginning of Period                                                      976              1,088
                                                                                                    ------            -------
Cash and Cash Equivalents at End of Period                                                           $858             $1,070
                                                                                                    ======            =======

Net Increase in Cash and Cash Equivalents from Discontinued Operations                                 $2                $15
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period                           13                 23
                                                                                                    ------            -------
Cash and Cash Equivalents from Discontinued Operations - End of Period                                $15                $38
                                                                                                    ======            =======

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest, net of capitalized amounts, was $378 million and $366 million in 2004 and 2003, respectively. Cash paid
(received) for income taxes was $(43) million and $155 million in 2004 and 2003, respectively. Noncash acquisitions under capital
leases were $27 million and $0 in 2004 and 2003, respectively.

In connection with the disposition of AEP Coal in April 2004 the buyer assumed $11 million of non-current liabilities.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                      CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND
                                                        COMPREHENSIVE INCOME
                                          For the Six Months Ended June 30, 2004 and 2003
                                                           (in millions)
                                                            (Unaudited)

                                                                                                          Accumulated
                                                             Common Stock                                   Other
                                                          -----------------   Paid-in       Retained     Comprehensive
                                                          Shares     Amount   Capital       Earnings     Income (Loss)      Total
                                                          ------     ------   -------       --------     -------------      -----
<C>                                                         <C>      <C>       <C>           <C>             <C>           <C>
DECEMBER 31, 2002                                           348      $2,261    $3,413        $1,999          $(609)        $7,064

Issuance of Common Stock                                     56         365       812                                       1,177
Common Stock Dividends                                                                         (342)                         (342)
Common Stock Expense                                                              (35)                                        (35)
Other                                                                              (8)            3                            (5)
                                                                                                                           -------
TOTAL                                                                                                                       7,859
                                                                                                                           -------

               COMPREHENSIVE INCOME
-------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
     Foreign Currency Translation Adjustments                                                                   23             23
     Cash Flow Hedges                                                                                         (100)          (100)
     Securities Available for Sale                                                                               1              1
     Minimum Pension Liability                                                                                  15             15
NET INCOME                                                                                      615                           615
                                                                                                                           -------
TOTAL COMPREHENSIVE INCOME                                                                                                    554
                                                            ----     -------   -------       -------         ------        -------

JUNE 30, 2003                                               404      $2,626    $4,182        $2,275          $(670)        $8,413
                                                            ====     =======   =======       =======         ======        =======


DECEMBER 31, 2003                                           404      $2,626    $4,184        $1,490          $(426)        $7,874

Issuance of Common Stock                                      1           4         7                                          11
Common Stock Dividends                                                                         (277)                         (277)
Other                                                                               2                                           2
                                                                                                                           -------
TOTAL                                                                                                                       7,610
                                                                                                                           -------

               COMPREHENSIVE INCOME
-------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
      Foreign Currency Translation Adjustments                                                                  (1)            (1)
      Cash Flow Hedges                                                                                          75             75
      Minimum Pension Liability                                                                                 17             17
NET INCOME                                                                                      382                           382
                                                                                                                           -------
TOTAL COMPREHENSIVE INCOME                                                                                                    473
                                                            ----     -------   -------       -------         ------        -------

JUNE 30, 2004                                               405      $2,630    $4,193        $1,595          $(335)        $8,083
                                                            ====     =======   =======       =======         ======        =======
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>

         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                     SCHEDULE OF CONSOLIDATED LONG-TERM DEBT
                       June 30, 2004 and December 31, 2003
                                   (Unaudited)



                                                    2004          2003
                                                    ----          ----
                                                       (in millions)

    TOTAL LONG-TERM DEBT OUTSTANDING
    --------------------------------
    First Mortgage Bonds                            $556          $822
    Defeased TCC First Mortgage Bonds (a)            112           118
    Installment Purchase Contracts                 1,936         2,026
    Notes Payable                                  1,409         1,518
    Senior Unsecured Notes                         7,840         7,997
    Securitization Bonds                             718           746
    Notes Payable to Trust                           254           331
    Equity Unit Senior Notes                         345           345
    Long-term DOE Obligation (b)                     227           226
    Other Long-term Debt                              41            21
    Equity Unit Contract Adjustment Payments          14            19
    Unamortized Discount (net)                       (54)          (68)
                                                 --------      --------

    TOTAL                                         13,398        14,101
    Less Portion Due Within One Year               1,865         1,779
                                                 --------      --------

    TOTAL LONG-TERM PORTION                      $11,533       $12,322
                                                 ========      ========

    (a) On May 7, 2004, we deposited cash and treasury securities of $124.5
    million with a trustee to defease all of TCC's outstanding First Mortgage
    Bonds. Trust fund assets related to this obligation of $103 million are
    included in Other Cash Deposits and $22 million in Other Non-current Assets
    in the Consolidated Balance Sheets at June 30, 2004. Trust fund assets are
    restricted for exclusive use in retiring the First Mortgage Bonds.

    (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear
    licensee) has an obligation with the United States Department of Energy for
    spent nuclear fuel disposal. The obligation includes a one-time fee for
    nuclear fuel consumed prior to April 7, 1983. I&M is the only AEP subsidiary
    that generated electric power with nuclear fuel prior to that date. Trust
    fund assets of $259 million and $262 million related to this obligation are
    included in Spent Nuclear Fuel and Decommissioning Trusts in the
    Consolidated Balance Sheets at June 30, 2004 and December 31, 2003,
    respectively.
<PAGE>



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



           1. Significant Accounting Matters

           2. New Accounting Pronouncements

           3. Rate Matters

           4. Customer Choice and Industry Restructuring

           5. Commitments and Contingencies

           6. Guarantees

           7. Dispositions, Discontinued Operations and Assets Held for Sale

           8. Benefit Plans

           9. Business Segments

          10. Financing Activities


<PAGE>

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

1.  SIGNIFICANT ACCOUNTING MATTERS
    ------------------------------

General
-------

The accompanying unaudited interim financial statements should be read in
conjunction with the 2003 Annual Report as incorporated in and filed with our
2003 Form 10-K.

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

Other Income (Expense), Net
---------------------------

The following table provides the components of Other Income (Expense), Net as
presented on our Consolidated Statements of Operations:

<TABLE>
<CAPTION>

                                                             Three Months Ended June 30,           Six Months Ended June 30,
                                                                 2004          2003                 2004              2003
                                                                 ----          ----                 ----              ----
                                                                                     (in millions)
<C>                                                               <C>           <C>                  <C>              <C>
Other Income:
-------------
Interest and Dividend Income                                       $5            $8                  $11               $13
Equity Earnings                                                     3             1                   10                 2
Nonoperating Revenue                                               28            38                   57                66
Gain on Sale of REPs (Mutual Energy Companies)                      -             -                    -                39
Other                                                              56            52                   85                89
                                                                  ----          ----                 ----             -----
Total Other Income                                                 92            99                  163               209
                                                                  ----          ----                 ----             -----

Other Expense:
--------------
Nonoperating Expenses                                              22            34                   46                60
Other                                                              19            15                   26                33
                                                                  ----          ----                 ----             -----
Total Other Expense                                                41            49                   72                93
                                                                  ----          ----                 ----             -----

Total Other Income (Expense), Net                                 $51           $50                  $91              $116
                                                                  ====          ====                 ====             =====

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

The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income
(Loss):
</TABLE>


Components                                          June 30,       December 31,
----------                                            2004             2003
                                                      ----             ----
                                                          (in millions)

Foreign Currency Translation Adjustments              $109             $110
Unrealized Losses on Securities Available for Sale      (1)              (1)
Unrealized Losses on Cash Flow Hedges                  (19)             (94)
Minimum Pension Liability                             (424)            (441)
                                                     ------           ------
Total                                                $(335)           $(426)
                                                     ======           ======

At June 30, 2004, we expect to reclassify approximately $12 million of net
losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to
Net Income during the next twelve months at the time the hedged transactions
affect net income. Two years is the maximum period over which an exposure to a
variability in future commodity or foreign currency related cash flows is hedged
with SFAS 133 designated contracts. Approximately $1 million of the fair value
of cash flow hedges at June 30, 2004 are hedging interest rate variability on
debt past two years. The actual amounts that we reclassify from Accumulated
Other Comprehensive Income (Loss) to Net Income can differ due to market price
changes.

In addition, during the first quarter 2004, we reclassified $23 million from
Accumulated Other Comprehensive Income (Loss) related to minimum pension
liability to regulatory assets ($35 million) and deferred income taxes ($12
million) as a result of authoritative letters issued by the FERC and the
Arkansas and Louisiana commissions.

Accounting for Asset Retirement Obligations
-------------------------------------------

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

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

<C>                                          <C>                     <C>                   <C>             <C>
Asset Retirement Obligation Liability
 at January 1, 2004 Including Held
 for Sale                                    $770.9                  $75.4                 $53.1           $899.4
Accretion Expense                              27.7                    3.0                   1.5             32.2
Foreign Currency
 Translation                                      -                      -                   0.3              0.3
Liabilities Incurred                              -                      -                  17.7             17.7
Liabilities Settled                               -                      -                 (11.3)           (11.3)
Revisions in Cash Flow Estimates                  -                      -                  15.0             15.0
                                             -------                 ------                ------          -------
Asset Retirement Obligation Liability
 at June 30, 2004 including Held
 for Sale                                     798.6                   78.4                  76.3            953.3

Less Asset Retirement Obligation
 Liability Held for Sale:
    South Texas Project (a)                  (227.0)                     -                     -           (227.0)
    U.K. Plants (b)                               -                      -                 (44.8)           (44.8)
                                             -------                 ------                ------          -------
Asset Retirement Obligation
 Liability at June 30, 2004                  $571.6                  $78.4                 $31.5           $681.5
                                             =======                 ======                ======          =======

(a) We have signed an agreement to sell TCC's share of South Texas Project (see Note 7 for additional information).
(b) We closed on the sale of our U.K. plants in late July 2004 (see Note 7 for additional information).
</TABLE>


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

As of June 30, 2004 and December 31, 2003, the fair value of assets that are
legally restricted for purposes of settling the nuclear decommissioning
liabilities totaled $885 million and $845 million, respectively, of which $754
million and $720 million relating to the Cook Plant was recorded in Spent
Nuclear Fuel and Decommissioning Trusts in our Consolidated Balance Sheets. The
fair value of assets that are legally restricted for purposes of settling the
nuclear decommissioning liabilities for the South Texas Project totaling $131
million and $125 million as of June 30, 2004 and December 31, 2003,
respectively, was classified as Assets Held for Sale in our Consolidated Balance
Sheets.

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

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

2.  NEW ACCOUNTING PRONOUNCEMENTS
    -----------------------------

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

We implemented FIN 46R, "Consolidation of Variable Interest Entities," effective
March 31, 2004 with no material impact to our financial statements. FIN 46R is a
revision to FIN 46 which 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.

FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements
 Related to the Medicare Prescription Drug Improvement and Modernization Act of
 2003
-------------------------------------------------------------------------------

We implemented FASB Staff Position (FSP) FAS 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003," effective April 1, 2004, retroactive to January 1,
2004. The new disclosure standard provides authoritative guidance on the
accounting for any effects of the Medicare prescription drug subsidy under the
Act. It replaces the earlier FSP FAS 106-1, under which we previously elected to
defer accounting for any effects of the Act until the FASB issued authoritative
guidance on the accounting for the Medicare subsidy.

Under FSP FAS 106-2, the current portion of the Medicare subsidy for employers
who qualify for the tax-free subsidy is a reduction of ongoing FAS 106 cost,
while the retroactive portion is an actuarial gain to be amortized over the
average remaining service period of active employees, to the extent that the
gain exceeds FAS 106's 10 percent corridor. The Medicare subsidy reduced our FAS
106 accumulated postretirement benefit obligation (APBO) related to benefits
attributed to past service by $202 million. The tax-free subsidy reduced the
second quarter's net periodic postretirement benefit cost by a total of $7
million, including $3 million of amortization of the actuarial gain, $1 million
of reduced service cost, and $3 million of reduced interest cost on the APBO.
After adjustment to capitalization of employee benefits costs as a cost of
construction projects, $5 million of this tax-free cost reduction remained to
increase the second quarter's net income.

The effect of implementing FSP FAS 106-2 on the first quarter of 2004 is as
follow:

Three Months Ended March 31, 2004     Earnings in Millions   Earnings Per Share
---------------------------------     --------------------   ------------------

Originally Reported                            $278                 $0.70
Effect of Medicare Subsidy                        5                  0.02
                                               -----                ------
Restated                                       $283                 $0.72
                                               =====                ======

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

The FASB's standard-setting process is ongoing and 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. The FASB is
currently working on several projects including discontinued operations,
business combinations, liabilities and equity, revenue recognition, accounting
for equity-based compensation, pension plans, asset retirement obligations,
earnings per share calculations, fair value measurements, and related tax
impacts. We also expect to see more projects as a result of the FASB's desire to
converge International Accounting Standards with those generally accepted in the
United States of America. The ultimate pronouncements resulting from these and
future projects could have an impact on our future results of operations and
financial position.

3.  RATE MATTERS
    ------------

As discussed in our 2003 Annual Report, our subsidiaries are involved in rate
and regulatory proceedings at the FERC and at several state commissions. The
Rate Matters note within our 2003 Annual Report should be read in conjunction
with this report in order to gain a complete understanding of material rate
matters still pending, without significant changes since year-end. The following
sections discuss current activities.

TNC Fuel Reconciliation
-----------------------

In 2002, TNC filed with the PUCT to reconcile fuel costs, requesting to defer
any unrecovered portion applicable to retail sales within its ERCOT service area
for inclusion in the 2004 true-up proceeding. This reconciliation for the period
from July 2000 through December 2001 will be the final fuel reconciliation for
TNC's ERCOT service territory.

In March 2003, the ALJ in this proceeding filed a Proposal for Decision (PFD)
with a recommendation that TNC's under-recovered retail fuel balance be reduced.
In March 2003, TNC established a reserve of $13 million based on the
recommendations in the PFD. In May 2003, the PUCT reversed the ALJ on certain
matters and remanded TNC's final fuel reconciliation to the ALJ to consider two
issues: (1) the sharing of off-system sales margins from AEP's trading
activities with customers for five years per the PUCT's interpretation of the
Texas AEP/CSW merger settlement and (2) the inclusion of January 2002 fuel
factor revenues and associated costs in the determination of the under-recovery.
The PUCT proposed that the sharing of off-system sales margins for periods
beyond the termination of the fuel factor should be recognized in the final fuel
reconciliation proceeding. This would result in the sharing of margins for an
additional three and one-half years after the end of the Texas ERCOT fuel
factor. While management believes that the Texas merger settlement only provided
for sharing of margins during the period fuel and generation costs were
regulated by the PUCT, an additional provision of $10 million was recorded in
December 2003.

In December 2003, the ALJ issued a PFD in the remand phase of the TNC fuel
reconciliation recommending additional disallowances for the two remand issues.
TNC filed responses to the PFD and the PUCT announced a final ruling in the fuel
reconciliation proceeding in January 2004 accepting the PFD. TNC received a
written order in March 2004 and increased the reserve by $1.5 million. In March
2004, various parties, including TNC, requested a rehearing of the PUCT's
ruling. In May 2004, the PUCT reversed its position on the inclusion of MTM
amounts in the allocation of system sales margins and remanded the case to the
ALJ. As a result, TNC recorded an additional provision of $12 million in the
second quarter of 2004 resulting in an over-recovery balance of $7 million at
June 30, 2004.

On July 2, 2004, the parties to the MTM remand proceeding filed a "Stipulation
of Fact." All parties agreed to the amount of the remanded issue. If the amounts
included in the "Stipulation of Fact" are approved, the over-recovery balance
will be reduced to $4 million. We expect the PUCT to issue its final order in
this proceeding in August 2004.

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

In 2002, TCC filed its final fuel reconciliation with the PUCT to reconcile fuel
costs to be included in its deferred over-recovery balance in the 2004 true-up
proceeding. This reconciliation covers the period from July 1998 through
December 2001.

Based on the PUCT ruling in the TNC proceeding relating to similar issues, TCC
established a reserve for potential adverse rulings of $81 million during 2003.
On February 3, 2004, the ALJ issued a PFD recommending that the PUCT disallow
$140 million in eligible fuel costs including some new items not considered in
the TNC case, and other items considered but not disallowed in the TNC ruling.
Based on an analysis of the ALJ's recommendations, TCC established an additional
reserve of $13 million during the first quarter of 2004. In May 2004, the PUCT
accepted most of the ALJ's recommendations. The PUCT rejected the ALJ's
recommendation to impute capacity to certain energy-only purchased power
contracts and remanded the issue to the ALJ to determine if any energy-only
purchased power contracts during the reconciliation period include a capacity
component that is not recoverable in fuel revenues. Hearings are scheduled in
October 2004 for the remand issue. As a result of the PUCT's acceptance of the
ALJ's recommendations and the PUCT's remand decision in the TNC case regarding
the inclusion of MTM amounts in the allocation of AEP's net system sales
margins, TCC increased its provision by $47 million in the second quarter of
2004. The over-recovery balance and the provisions total $210 million including
interest at June 30, 2004. At this time, management is unable to predict the
outcome of this proceeding. An adverse ruling from the PUCT, disallowing amounts
in excess of the established reserve, could have a material impact on future
results of operations and cash flows. 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
--------------------------------

In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in the SPP.
This reconciliation covers the period from January 2000 through December 2002.
During the reconciliation period, SWEPCo incurred $435 million of Texas retail
eligible fuel expense. In November 2003, intervenors and the PUCT Staff
recommended fuel cost disallowances of more than $30 million. In December 2003,
SWEPCo agreed to a settlement in principle with all parties in the fuel
reconciliation. The settlement provides for a disallowance in fuel costs of $8
million which was recorded in December 2003. In April 2004 the PUCT approved the
settlement.

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

On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates should not be
reduced. Other municipalities served by TCC passed similar rate review
resolutions. In Texas, municipalities have original jurisdiction over rates of
electric utilities within their municipal limits. Under Texas law, TCC must
provide support for its rates to the municipalities. TCC filed the requested
support for its rates based on a test year ending June 30, 2003 with all of its
municipalities and the PUCT on November 3, 2003. TCC's proposal would decrease
its wholesale transmission rates by $2 million or 2.5% and increase its retail
energy delivery rates by $69 million or 19.2%. In February 2004, eight
intervening parties and the PUCT Staff filed testimony recommending reductions
to TCC's requested $67 million rate increase. The recommendations ranged from a
decrease in existing rates of approximately $100 million to an increase in TCC's
current rates of approximately $27 million. Hearings were held in March 2004. In
May 2004, TCC agreed to a non-unanimous settlement on cost of capital including
capital structure and return on equity with all but two parties in the
proceeding. TCC agreed that the return on equity should be established at
10.125% based upon a capital structure with 40% equity resulting in a weighted
cost of capital of 7.475%. The settlement and other agreed adjustments reduced
TCC's rate request to $41 million. The ALJs that heard the case issued their
recommendations on July 2, 2004, including a recommendation to approve the cost
of capital settlement. The ALJs recommended that an issue related to the
allocation of consolidated tax savings to the transmission and distribution
utility be remanded for additional evidence. On July 15, 2004, the PUCT agreed
to remand this issue to the ALJs. In addition, the PUCT ordered TCC to calculate
its revenue requirements based upon the recommendations of the ALJs. On July 21,
2004, TCC filed its revenue requirements based upon the recommendations of the
ALJs. The ALJs' recommendations reduce TCC's existing rates by a range of $33
million to $43 million depending on the final resolution of the amount of
consolidation tax savings. TCC filed exceptions to the ALJs' recommendations on
July 21, 2004. The PUCT is expected to issue its decision in September 2004.
Management is unable to predict the ultimate effect of this proceeding on TCC's
rates, revenues, results of operations, cash flows and financial condition.

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

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

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

In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting
from a reallocation among AEP West companies of purchased power costs for
periods prior to January 1, 2002. In July 2003, PSO filed with the Corporation
Commission of the State of Oklahoma (OCC) seeking to recover these costs over a
period of 18 months. In August 2003, the OCC Staff filed testimony recommending
PSO be granted recovery of $42.4 million over three years. In September 2003,
the OCC expanded the case to include a full review of PSO's 2001 fuel and
purchased power practices. PSO filed its testimony in February 2004. An
intervenor and the OCC Staff filed testimony in April 2004. The intervenor
suggested that $8.8 million related to the 2002 reallocation not be recovered
from customers. The Attorney General of Oklahoma also filed a statement of
position, indicating allocated trading margins between and among AEP operating
companies were inconsistent with the FERC-approved Operating Agreement and
System Integration Agreement and could more than offset the $44 million 2002
reallocation. The intervenor and the OCC Staff also believed trading margins
were allocated incorrectly and that a reallocation by the intervenors of such
margins would reduce PSO's recoverable fuel by approximately $6.8 million for
2000 and $10.7 million for 2001, while under the OCC Staff method, the amount
for 2001 would be $8.8 million. The intervenor and the OCC Staff also recommend
recalculation of fuel for years subsequent to 2001 using the same methods. At a
June 2004 prehearing conference, PSO questioned whether the issues in dispute
were the jurisdiction of the OCC or the FERC because they relate to the
FERC-approved agreements. As a result, the ALJ ordered that the jurisdictional
issue be briefed by the parties. PSO is required to file its brief by September
1, 2004. Subject to decisions by the OCC as to jurisdiction, a hearing date has
been set for January 2005. Management believes that fuel costs have been
prudently incurred consistent with OCC rules, and that the allocation of trading
margins pursuant to the agreements is correct. If the OCC determines, as a
result of the review that a portion of PSO's fuel and purchased power costs
should not be recovered, there will be an adverse effect on PSO's results of
operations, cash flows and possibly financial condition.

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

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 $33
million of RTO formation and integration costs and related carrying charges
through June 30, 2004. As a result of the subsequent delay in the integration of
AEP's East transmission system into PJM, FERC declined to rule, in its July 2003
order, on our request to transfer the deferrals to regulatory assets, and to
maintain the deferrals until such time as the costs can be recovered from all
users of AEP's East transmission system. The AEP East companies plan to apply
for permission to transfer the deferred formation/integration costs to a
regulatory asset prior to integration with PJM.

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
prudently incurred deferred RTO formation/integration 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 as these companies file rate cases. Presently, retail base
rates are frozen or capped and cannot be increased for retail customers of
CSPCo, I&M and OPCo.

In August 2004, we intend to file an application with FERC dividing the RTO
formation/integration costs between payments made to PJM and all other costs. We
will subsequently request that the payments made directly to PJM be recovered
from all users of PJM's transmission and that the balance of the deferred costs
be recovered from load-serving entities within the area served by the AEP East
companies' owned transmission (AEP zone). Most of the amount recoverable in the
AEP zone will be paid by the AEP East companies since it will be attributable to
their internal load. The amount to be recovered in the AEP zone is approximately
one-half of the deferred costs. In our August application, we will seek
permission to delay the amortization of the AEP zone deferred amounts until they
are recoverable from users of the transmission system including our retail
customers or, as an alternative, to use a long amortization period that extends
beyond the rate freezes or caps.

The AEP East companies are scheduled to join PJM in October 2004, although there
are pending proceedings in Virginia concerning our integration into PJM.
Therefore, 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 or a long enough amortization period to allow for the
opportunity for recovery in the East retail jurisdictions. If the AEP East
companies do not obtain regulatory approval to join PJM, we are committed to
reimburse PJM for certain project implementation costs (presently estimated at
$24 million for our share of the entire PJM integration project). Management
intends to seek recovery of the project implementation cost reimbursements, if
incurred. If the FERC ultimately decides not to approve a delay or a long
amortization period or the FERC or the state commissions deny recovery, future
results of operations and cash flows could be adversely affected.

In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO prior to July 1, 2004 and thereafter only
with the approval of the Virginia SCC, but required such transfers by January 1,
2005. In January 2004, APCo filed with the Virginia SCC a cost/benefit study
covering the time period through 2014 as required by the Virginia SCC. The study
results show a net benefit of approximately $98 million for APCo over the
11-year study period from AEP's participation in PJM. In July 2004, after
reaching a unanimous agreement with intervenors to settle the RTO issues in
Virginia, the settlement agreement was submitted to the Virginia SCC. The
settlement provides for approval of APCo's application to join PJM in exchange
for a small annual revenue credit to customers through 2010, or the effective
date of rates established in a new base rate case, some service curtailment
provisions and annual reporting requirements.

In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack
of evidence that it would benefit Kentucky retail customers. In August 2003,
KPCo sought and was granted a rehearing to submit additional evidence. In
December 2003, AEP filed with the KPSC a cost/benefit study showing a net
benefit of approximately $13 million for KPCo over the five-year study period
from AEP's participation in PJM. In April 2004, we reached an agreement with
interveners to settle the RTO issues in Kentucky. The KPSC approved the
agreement in May 2004 and the FERC approved the settlement in June 2004.

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

In November 2003, the FERC issued an order preliminarily finding that AEP must
fulfill its CSW merger condition to join an RTO by integrating into PJM
(transmission and markets) by October 1, 2004. The order was based on PURPA
205(a), which allows FERC to exempt electric utilities from state law or
regulation in certain circumstances. The FERC set several issues for public
hearing before an ALJ. Those issues include whether the laws, rules, or
regulations of Virginia and Kentucky are preventing AEP from joining an RTO and
whether the exceptions under PURPA 205(a) apply. The FERC ALJ affirmed the
FERC's preliminary findings in March 2004. The FERC issued an order related to
this matter in June 2004 affirming its preliminary findings. Virginia requested
a stay of the FERC order, which was denied, and Virginia now has requested a
stay in the courts.

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

In July 2003, the FERC issued an order directing PJM and the Midwest Independent
System Operator (ISO) to make compliance filings for their respective OATTs to
eliminate the transaction-based charges for through and out (T&O) transmission
service on transactions where the energy is delivered within the proposed
Midwest ISO and PJM expanded regions (RTO Footprint). The elimination of the T&O
rates will reduce the transmission service revenues collected by the RTOs and
thereby reduce the revenues received by transmission owners under the RTOs'
revenue distribution protocols. The order provided that affected transmission
owners could file to offset the elimination of these revenues by increasing
rates or utilizing a transitional rate mechanism to recover lost revenues that
result from the elimination of the T&O rates. The FERC also found that the T&O
rates of some of the former Alliance RTO companies, including AEP, may be
unjust, unreasonable, and unduly discriminatory or preferential for energy
delivered in the RTO Footprint. FERC initiated an investigation and hearing in
regard to these rates.

In November 2003, the FERC adopted a new regional rate design and directed each
transmission provider to file compliance rates to eliminate T&O rates
prospectively within the region and simultaneously implement new seams
elimination cost allocation (SECA) rates to mitigate the lost revenues for a
two-year transition period beginning April 1, 2004. The FERC was expected to
implement a new rate design after the two-year period. As required by the FERC,
we filed compliance tariff changes in January 2004 to eliminate the T&O charges
within the RTO Footprint. Various parties raised issues with the SECA rate
orders and FERC implemented settlement procedures before an ALJ.

In March 2004, the FERC approved a settlement that delays elimination of T&O
rates until December 1, 2004 and provides principles and procedures for a new
rate design for the RTO Footprint, to be effective on December 1, 2004. The
settlement also provides that if the process does not result in the
implementation of a new rate design on December 1, then the SECA rates will be
implemented and will remain in effect until a new rate is implemented by the
FERC. If implemented, the SECA rate would not be effective beyond March 31,
2006. The AEP East companies received approximately $157 million of T&O rate
revenues from transactions delivering energy to customers in the RTO Footprint
for the twelve months ended December 31, 2003. At this time, management is
unable to predict whether the new rate design will fully compensate the AEP East
companies for their lost T&O rate revenues and, consequently, their impact on
our future results of operations, cash flows and financial condition.

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

On August 27, 2003, the IURC ordered that certain parties must negotiate the
appropriate action on I&M's fuel cost recovery beginning March 1, 2004,
following the February 2004 expiration of a fixed fuel adjustment charge (fixed
pursuant to a prior settlement of the Cook Nuclear Plant outage issues). The
fixed fuel adjustment charge capped fuel recoveries. In an agreement in
connection with AEP's planned corporate separation, I&M agreed, contingent on
AEP implementing the corporate separation, to a fixed fuel adjustment charge
beginning March 2004 and continuing through December 2007. Although we have not
corporately separated, certain parties believe the fixed fuel adjustment charge
should continue. Negotiations with the parties to resolve this issue are
ongoing. The IURC ordered the fixed fuel adjustment charge remain in place, on
an interim basis, for March and April 2004.

In April 2004, the IURC issued an order that extended the interim fuel factor
for May through September 2004, subject to true-up to actual fuel costs
following the resolution of issues in the corporate separation agreement. The
IURC also issued an order that reopened the corporate separation docket to
investigate issues related to the corporate separation agreement. On July 15,
2004, we filed a fuel factor for the period October 2004 through March 2005. If
the IURC reinstates a fixed fuel adjustment factor, capping the fuel revenues,
results of operations and cash flows would be adversely affected if fuel costs
are under-recovered.

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

A 1999 Michigan Public Service Commission's (MPSC) 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. As required, I&M filed its 2004 PSCR Plan with the
MPSC on September 30, 2003 seeking new fuel and power supply recovery factors to
be effective in 2004. A public hearing occurred on March 10, 2004 and a MPSC
order is expected during the second half of 2004. On June 4, 2004, an ALJ
recommended that SO2 and NOx costs be excluded. We filed our exceptions on June
18, 2004. As allowed by Michigan law, the proposed factors were effective on
January 1, 2004, subject to review and possible adjustment based on the results
of the MPSC order.

4.  CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
    ------------------------------------------

As discussed in our 2003 Annual Report, we are affected by customer choice
initiatives and industry restructuring. The Customer Choice and Industry
Restructuring note in our 2003 Annual Report should be read in conjunction with
this report in order to gain a complete understanding of material customer
choice and industry restructuring matters without significant changes since
year-end. The following paragraphs discuss significant current events related to
customer choice and industry restructuring.

OHIO RESTRUCTURING
------------------

The Ohio Electric Restructuring Act of 1999 (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 Public Utilities Commission of
Ohio (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 cost-based regulated distribution and transmission
service from the incumbent utility whose distribution rates will be approved by
the PUCO and whose transmission rates will be approved by the FERC. Retail
customers will continue to have the right to choose their electric power
suppliers or receive Default Service, which must be offered by the incumbent
utility at market rates.

On December 17, 2003, the PUCO adopted a set of rules concerning the method by
which it will determine market rates for Default Service following the MDP. The
rule provides for a Market Based Standard Service Offer (MBSSO) which would be a
variable rate based on a transparent forward market, daily market, and/or hourly
market prices. The rule also requires a fixed-rate Competitive Bidding Process
(CBP) for residential and small nonresidential customers and permits a
fixed-rate CBP for large general service customers and other customer classes.
Customers who do not switch to a competitive generation provider can choose
between the MBSSO or the CBP. Customers who make no choice will be served
pursuant to the CBP. The companies were granted a waiver from making the
required MBSSO/CBP filing, as a result of their rate stabilization plan filing.

The PUCO invited default service providers to propose an alternative to all
customers moving to market prices on January 1, 2006. On February 9, 2004, CSPCo
and OPCo filed their rate stabilization plan with the PUCO addressing prices
following the end of the MDP. If approved by the PUCO, prices would be
established pursuant to the plan for the period from January 1, 2006 through
December 31, 2008. The plan is intended to provide price stability and certainty
for customers, facilitate the development of a competitive retail market in
Ohio, provide recovery of environmental and other costs during the plan period
and improve the environmental performance of AEP's generation resources that
serve Ohio customers. The plan includes annual, fixed increases in the
generation component of all customers' bills (3% annually for CSPCo and 7%
annually for OPCo), and the opportunity for additional generation-related
increases upon PUCO review and approval. For residential customers, however, if
the temporary 5% generation rate discount provided by the Ohio Act were
eliminated prior to December 31, 2005 as permitted by the Ohio Act, the fixed
increases would be 1.6% for CSPCo and 5.7% for OPCo. Any additional
generation-related increases under the plan would be subject to caps. The plan
would maintain distribution rates through the end of 2008 for CSPCo and OPCo at
the level effective on December 31, 2005. Such rates could be adjusted for
specified reasons. Transmission charges can be adjusted to reflect applicable
charges approved by the FERC related to open access transmission, net
congestion, and ancillary services. The plan also provides for continued
recovery of transition regulatory assets and deferral of regulatory assets in
2004 and 2005 for RTO costs and carrying charges on governmentally mandated,
mainly environmental, capital expenditures. Hearings were held in June 2004.
Briefings were completed in July and the cases are pending before the PUCO.
Management cannot predict whether the plan will be approved as submitted or its
impact on results of operations and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000, we are
deferring customer choice implementation costs and related carrying costs that
are in excess of $40 million. The agreements provide for the deferral of these
costs as a regulatory asset until the next distribution base rate cases. Through
June 30, 2004, we incurred $72 million, and accordingly, we deferred $32 million
of such costs. Recovery of these regulatory assets will be subject to PUCO
review in future Ohio filings for new distribution rates. If the rate
stabilization plan is approved, it would defer recovery of these amounts until
after the end of the rate stabilization period. Management believes that the
customer choice implementation costs were prudently incurred and the deferred
amounts should be recoverable in future rates. If the PUCO determines that any
of the deferred costs are unrecoverable, it would have an adverse impact on
future results of operations and cash flows.

TEXAS RESTRUCTURING
-------------------

Texas Legislation enacted in 1999 provides the framework and timetable to allow
retail electricity competition for all Texas customers. On January 1, 2002,
customer choice of electricity supplier began in the ERCOT area of Texas.
Customer choice has been delayed in the SPP area of Texas until at least January
1, 2007.

The Texas Legislation, among other things:
 o  provides for the recovery of regulatory assets and other stranded costs
    through securitization and non-bypassable wires charges;
 o  requires each utility to structurally unbundle into a retail electric
    provider, a power generation company and a transmission and distribution
    (T&D) utility;
 o  provides for an earnings test for each of the years 1999 through 2001
    and;
 o  provides for a 2004 true-up proceeding.

The Texas Legislation required vertically integrated utilities to legally
separate their generation and retail-related assets from their transmission and
distribution-related assets. Prior to 2002, TCC and TNC functionally separated
their operations to comply with the Texas Legislation requirements. AEP formed
new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1,
2002 (the start date of retail competition). In December 2002, AEP sold the
affiliated REPs to an unaffiliated company.

TEXAS 2004 TRUE-UP PROCEEDINGS
------------------------------

The 2004 true-up proceedings will determine the amount and recovery of:
 o  net stranded generation plant costs and generation-related regulatory
    assets (stranded plant costs),
 o  carrying charges on stranded plant costs at a weighted cost of capital from
    January 2002 (the commencement date of retail competition),
 o  a true-up of actual market prices determined through legislatively-mandated
    capacity auctions to the power costs used in the PUCT's excess cost over
    market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up),
 o  final approved deferred fuel balance,
 o  unrefunded accumulated excess earnings,
 o  excess of price-to-beat revenues over market prices subject to certain
    conditions and limitations (retail clawback) and
 o  other restructuring true-up items.

The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up
proceedings scheduling TCC's filing in September 2004 or 60 days after the
completion of the sale of TCC's generation assets, if later. TNC filed its 2004
true-up proceeding in June 2004.

Summary of TCC True-up Items
----------------------------
                                                    Amount Recorded
                                                   at June 30, 2004
                                                   ----------------
                                                    (in millions)

Stranded Generation Plant Costs                         $1,074  (a)
Unsecuritized Transition Regulatory Asset                  194  (a)
Unrefunded Excess Earnings                                 (19) (b)
Other                                                      (46)
                                                        -------
  Amount Subject to Future Securitization                1,203
                                                        -------

Wholesale Capacity Auction True-up                         480  (c)
Retail Clawback                                            (30) (d)
Deferred Over-recovered Fuel                              (210) (e)
                                                        -------
  Other Recoverable Amounts                                240
                                                        -------
Total Recorded 2004 True-up Balance                     $1,443  (f)
                                                        =======

(a) See "Stranded Costs and Generation-Related Regulatory Assets" section below
    for additional information on this item.
(b) See "Unrefunded Excess Earnings" section below for additional information
    on this item.
(c) See "Wholesale Capacity Auction True-up" section below for additional
    information on this item.
(d) See "Retail Clawback" section below for additional information on this item.
(e) See "Fuel Balance Recoveries" section below for additional information on
    this item.
(f) See "Stranded Cost Recovery" section below for summary of this balance.


Stranded Costs and Generation-Related Regulatory Assets
-------------------------------------------------------

Restructuring legislation required utilities with stranded costs to use
market-based methods to value certain generation assets for determining stranded
costs. TCC is the only AEP subsidiary that has stranded costs under the Texas
Legislation. We elected to use the sale of assets method to determine the market
value of TCC's generation assets for stranded cost purposes. For purposes of the
2004 true-up proceeding, the amount of stranded costs under this market
valuation methodology will be the amount by which the book value of TCC's
generation 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. Based on the prices established by
the sales, discussed below, TCC's stranded costs from the sale of TCC's
generation assets and remaining generation-related net regulatory assets are
estimated to be $1.3 billion ($1,074 million and $194 million, described later
in this section) before accrual of any applicable carrying charges.

In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's
generation capacity in Texas with a net book value of $1.9 billion at June 30,
2004. We received bids for all of TCC's generation plants. In January 2004, TCC
agreed to sell its 7.81% ownership interest in the Oklaunion Power Station to an
unaffiliated third party for approximately $43 million. In March 2004, TCC
agreed to sell its 25.2% ownership interest in STP for approximately $333
million and its other coal, gas and hydro plants for approximately $430 million
to unaffiliated entities. Each sale is subject to specified price adjustments.
TCC sent right of first refusal notices to the co-owners of Oklaunion and STP.
TCC filed for FERC approval of the sales of Oklaunion and the fossil and hydro
plants. We have received a notice from co-owners of Oklaunion and STP exercising
their right of first refusal; therefore, SEC approval will be required. The
original unaffiliated third party purchaser of Oklaunion has petitioned for a
court order declaring its contract valid and that the co-owners' rights of first
refusal are void. Approval of the sale of STP from the Nuclear Regulatory
Commission is required. On July 1, 2004, we completed the sale of the other
coal, gas and hydro plants for approximately $425 million, net of adjustments.
The completion of the sales of STP and Oklaunion plants is expected to occur in
2004, subject to the rights of first refusal and the necessary regulatory
approvals. In order to sell these assets, TCC defeased all of its remaining
outstanding first mortgage bonds in May 2004. TCC will file its 2004 true-up
proceeding with the PUCT after the completion of the sale of the generation
assets.

After the 2004 true-up proceeding, TCC may recover stranded costs and other
true-up amounts through distribution rates as a competition transition charge
and may seek to issue securitization revenue bonds for its stranded plant costs
and remaining generation net regulatory assets. The cost of the securitization
bonds is recovered through distribution rates as a separate transition charge.
We recognized an impairment of TCC's generation assets in December 2003 as a
regulatory asset. At June 30, 2004, this regulatory asset was approximately
$1,074 million. The recovery of this regulatory asset and the remaining $194
million of generation-related net regulatory assets will be subject to review
and approval by the PUCT as a stranded plant cost in the 2004 true-up
proceeding.

Carrying Charges On Recoverable Stranded Costs
----------------------------------------------

In December 2001, the PUCT issued a rule concerning stranded cost true-up
proceedings stating, among other things, that carrying costs on stranded costs
would begin to accrue on the date that the PUCT issued its final order in the
2004 true-up proceeding. TCC and one other Texas electric utility company filed
a direct appeal of the rule to the Texas Third Court of Appeals contending that
carrying costs should commence on January 1, 2002, the day that retail customer
choice began in ERCOT.

The Third Court of Appeals ruled against the companies, who then appealed to the
Texas Supreme Court. On June 18, 2004, the Texas Supreme Court reversed the
decision of the Third Court of Appeals determining that a carrying cost should
be accrued beginning January 1, 2002 and remanded the proceeding to the PUCT for
further consideration. The Supreme Court determined that utilities with stranded
costs are not permitted to over-recover stranded costs and the PUCT should
address whether the 2002 and 2003 wholesale capacity auction true-up regulatory
asset includes a recovery of stranded costs. Industrial intervenors have filed a
motion for rehearing with the Supreme Court which has not been decided.

The PUCT has indicated that it will consider the Supreme Court's decision in
hearings to be held for another utility in September 2004. The decision in that
proceeding could have an impact on TCC. Since the impact of these future PUCT
proceedings cannot be determined at this time, TCC has not recorded the carrying
charge as a regulatory asset through June 30, 2004.

Wholesale Capacity Auction True-up
----------------------------------

Texas Legislation required that electric utilities and their affiliated power
generation companies (PGC) offer for sale at auction, in 2002 and 2003 and
after, at least 15% of the PGC's Texas jurisdictional installed generation
capacity in order to promote competitiveness in the wholesale market through
increased availability of generation. Actual market power prices received in the
state-mandated auctions will be used to calculate the wholesale capacity auction
true-up adjustment for TCC for the 2004 true-up proceeding. According to PUCT
rules, the wholesale capacity auction true-up is only applicable to the years
2002 and 2003. TCC recorded a $480 million regulatory asset and related revenues
which represent the quantifiable amount of the wholesale capacity auction
true-up for the years 2002 and 2003.

In the fourth quarter of 2003, the PUCT approved a true-up filing package
containing calculation instructions similar to the methodology employed by TCC
to calculate the amount recorded for recovery under its wholesale capacity
auction true-up. The PUCT will review the $480 million wholesale capacity
auction true-up regulatory asset for recovery as part of the 2004 true-up
proceeding.

Fuel Balance Recoveries
-----------------------

In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail sales
within its ERCOT service area for inclusion in the 2004 true-up proceeding. In
January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation
case. The PUCT issued a written order in March 2004 that established TNC's
unrecovered fuel balance for the ERCOT service territory. Various parties,
including TNC, requested rehearing of the PUCT's order. In May 2004, the PUCT
reversed certain prior rulings resulting in TNC having a final fuel
over-recovery balance of approximately $7 million. TNC's 2004 true-up
proceeding, filed in June 2004, will be updated to reflect the balance after the
PUCT issues a final fuel order. TNC has provided for all to-date disallowances
pending receipt of the final order. Management is unable to predict the amount
of TNC's fuel over-recovery which will be included in its 2004 true-up
proceedings.

In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its
deferred over-recovery of fuel balance for inclusion in the 2004 true-up
proceeding. In May 2004, the PUCT remanded TCC's fuel proceeding to the ALJ. TCC
has provided $210 million for its over-recovery balance at June 30, 2004. TCC
has provided for all to-date disallowances pending receipt of a final order.
Management is unable to predict the amount of TCC's fuel over-recovery which
will be included in its 2004 true-up proceeding.

See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 3 "Rate Matters"
for further discussion.

Unrefunded Excess Earnings
--------------------------

The Texas Legislation provides for the calculation of excess earnings for each
year from 1999 through 2001. The total excess earnings determined for the three
year period were $3 million for SWEPCo, $47 million for TCC and $19 million for
TNC. TCC, TNC and SWEPCo challenged the PUCT's treatment of fuel-related
deferred income taxes and appealed the PUCT's final 2000 excess earnings to the
Travis County District Court which upheld the PUCT ruling. The District Court's
ruling was appealed to the Third Court of Appeals. In August 2003, the Third
Court of Appeals reversed the PUCT order and the District Court's judgment. The
PUCT's request for rehearing of the Appeals Court's decision was denied and the
PUCT chose not to appeal the ruling any further. The District Court remanded to
the PUCT an appeal of the same issue from the PUCT's 2001 order to be consistent
with the Court of Appeals decision. Since an expense and regulatory liability
had been accrued in prior years in compliance with the PUCT orders, the
companies reversed a portion of their regulatory liability for the years 2000
and 2001 consistent with the Appeals Court's decision and credited amortization
expense during the third quarter of 2003.

In 2001, the PUCT issued an order requiring TCC to return estimated excess
earnings by reducing distribution rates by approximately $55 million plus
accrued interest over a five-year period beginning January 1, 2002. Since excess
earnings amounts were expensed in 1999, 2000 and 2001, the order had no
additional effect on reported net income but will reduce cash flows for the
five-year refund period. The amount to be refunded is recorded as a regulatory
liability ($19 million at June 30, 2004). Management believes that TCC will have
stranded costs and that it was inappropriate for the PUCT to order a refund
prior to TCC's 2004 true-up proceeding. TCC appealed the PUCT's refund of excess
earnings to the Travis County District Court. That court affirmed the PUCT's
decision and further ordered that the refunds be provided to ultimate customers.
TCC has appealed the decision to the Court of Appeals.

Retail Clawback
---------------

The Texas Legislation provides for the affiliated price-to-beat (PTB) retail
electric providers (REP) serving residential and small commercial customers to
refund to its T&D utility the excess of the PTB revenues over market prices
(subject to certain conditions and a limitation of $150 per customer). This is
the retail clawback. If, prior to January 1, 2004, 40% of the load for the
residential or small commercial classes is served by competitive REPs, the
retail clawback is not applicable for that class of customer. During 2003, TCC
and TNC filed to notify the PUCT that competitive REPs serve over 40% of the
load in the small commercial class. The PUCT approved TCC's and TNC's filings in
December 2003. In 2002, AEP had accrued a regulatory liability of approximately
$9 million for the small commercial retail clawback on its REP's books. When the
PUCT certified that the REP's in TCC and TNC service territories had reached the
40% threshold, the regulatory liability was no longer required for the small
commercial class and was reversed in December 2003. Based upon customer
information filed by the unaffiliated company which operates as the affiliated
REP for TCC and TNC, we updated the estimated retail clawback regulatory
liability in May 2004. At June 30, 2004, AEP's retail clawback regulatory
liability was $37 million ($30 million related to TCC and $7 million related to
TNC).

TNC 2004 True-up Filing
-----------------------

In June 2004, TNC filed its 2004 true-up proceeding including the fuel
reconciliation balance and the retail clawback calculation. The amount of
deferred fuel, presently an over-recovery balance of $7 million, remains under
review by the PUCT and is subject to possible revision. The retail clawback
regulatory liability was adjusted in the second quarter of 2004 to $7 million
(TNC's allocated portion of the REP's retail clawback) reflecting the number of
customers served on January 1, 2004. The PUCT has deferred this proceeding
pending the resolution of the final fuel proceeding.

Stranded Cost Recovery
----------------------

When the 2004 true-up proceeding is completed, TCC intends to file to recover
PUCT-approved stranded costs and other true-up amounts that are in excess of
current securitized amounts, plus appropriate carrying charges, through a
non-bypassable competition transition charge in the regulated rates. TCC may
also seek to securitize the approved stranded plant costs and generation-related
net regulatory assets that were not previously recovered through a prior
securitization and the non-bypassable transition charge. The annual costs of
securitization are recovered through the non-bypassable transition charge
collected by the T&D utility over the term of the securitization bonds.

TCC's recorded net regulatory asset for stranded cost in the 2004 true-up
proceeding is approximately $1.4 billion. We estimate that TCC's 2004 true-up
filing will exceed the total of its recorded net regulatory asset. Management
expects that the 2004 true-up proceeding will be contentious and could possibly
result in disallowances.

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

VIRGINIA RESTRUCTURING
----------------------

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

5.  COMMITMENTS AND CONTINGENCIES
    -----------------------------

As discussed in the Commitments and Contingencies note within our 2003 Annual
Report, we continue to be involved in various legal matters. The 2003 Annual
Report should be read in conjunction with this report in order to understand the
other material nuclear and operational matters without significant changes since
our disclosure in the 2003 Annual Report. The material matters discussed in the
2003 Annual Report without significant changes in status since year-end include,
but are not limited to, (1) nuclear matters, (2) construction commitments, (3)
potential uninsured losses, (4) merger litigation, (5) shareholder lawsuits, (6)
California lawsuits, (7) Cornerstone lawsuit, (8) Bank of Montreal Claim, and
(9) FERC proposed Standard Market Design. See disclosure below for significant
matters with changes in status subsequent to the disclosure made in our 2003
Annual Report.

ENVIRONMENTAL
-------------

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

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

Under the CAA, if a plant undertakes a major modification that directly results
in an emissions increase, permitting requirements might be triggered and the
plant may be required to install additional pollution control technology. This
requirement does not apply to activities such as routine maintenance,
replacement of degraded equipment or failed components, or other repairs needed
for the reliable, safe and efficient operation of the plant. The CAA 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 June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to
"perfect" its complaint in the pending litigation. The NOV expands the number of
alleged "modifications" undertaken at the Muskingum River, Cardinal, Conesville
and Tanners Creek plants during scheduled outages on these units from 1979
through the present. Approximately one-third of the allegations in the NOV are
already contained in allegations made by the states or the special interest
groups in the pending litigation. The Federal EPA is expected to file a motion
to amend its complaint, and, to the extent that motion seeks to expand the scope
of the pending litigation, the AEP subsidiaries will oppose that motion.

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 was scheduled for July 2004, but has been postponed until January
2005 to facilitate further settlement negotiations.

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

On August 26, 2003, the District Court for the Middle District of South Carolina
issued a decision on cross-motions for summary judgment prior to a liability
trial in a case pending against Duke Energy Corporation, an unaffiliated
utility. The District Court denied all the pending motions, but set forth the
legal standards that will be applied at the trial in that case. The District
Court determined that the Federal EPA bears the burden of proof on the issue of
whether a practice is "routine maintenance, repair, or replacement" and on
whether or not a "significant net emissions increase" results from a physical
change or change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the relevant
source category" in determining if it is "routine." Further, the Federal EPA
must calculate emissions by determining first whether a change in the maximum
achievable hourly emission rate occurred as a result of the change, and then
must calculate any change in annual emissions holding hours of operation
constant before and after the change. The Federal EPA requested reconsideration
of this decision, or in the alternative, certification of an interlocutory
appeal to the Fourth Circuit Court of Appeals, and the District Court denied the
Federal EPA's motion. On April 13, 2004, the parties filed a joint motion for
entry of final judgment, based on stipulations of relevant facts that obviated
the need for a trial, but preserving plaintiffs' right to seek an appeal of the
federal prevention of significant deterioration (PSD) claims. On April 14, 2004,
the Court entered final judgment for Duke Energy on all of the PSD claims made
in the amended complaints, and dismissed all remaining claims with prejudice.
The United States subsequently filed a notice of appeal to the Fourth Circuit
Court of Appeals, which issued a briefing order requiring the case to be fully
briefed by late September 2004.

On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued
an order invalidating the administrative compliance order issued by the Federal
EPA to the Tennessee Valley Authority for alleged CAA 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 CAA are unconstitutional. The United States
filed a petition for certiorari with the United States Supreme Court and on May
3, 2004, that petition was denied.

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 a prospective effect, and was to become effective in
certain states 60 days after October 27, 2003, the date of its publication in
the Federal Register, and in other states upon completion of state processes to
incorporate the new rule into state law. On October 27, 2003 twelve states, the
District of Columbia and several cities filed an action in the United States
Court of Appeals for the District of Columbia Circuit seeking judicial review of
the new rule. The UARG has intervened in this case. On December 24, 2003, the
Circuit Court granted a motion from the petitioners to stay the effective date
of this rule, which had been December 26, 2003.

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

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

On July 21, 2004, the Sierra Club issued a notice of intent to file a citizen
suit claim against DPL, Inc., Cinergy Corporation, CSPCo, and The Dayton Power &
Light Company for alleged violations of the New Source Review programs at the
Stuart Station. CSPCo owns a 26% share of the Stuart Station. Management is
unable to predict the timing of any future action by the special interest group
or the effect of such actions on future operations or cash flows.

SWEPCo Notice of Enforcement and Notice of Citizen Suit
-------------------------------------------------------

On July 13, 2004, two special interest groups issued a notice of intent to
commence a citizen suit under the Clean Air Act for alleged violations of
various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and
Pirkey plants. This notice was prompted by allegations made by a terminated
AEP employee. The allegations at the Welsh Plant concern compliance with
emission limitations on particulate matter and carbon monoxide, compliance with
a referenced design heat input valve, and compliance with certain reporting
requirements. The allegations at the Knox Lee Plant relate to the receipt of an
off-specification fuel oil, and the allegations at Pirkey Plant relate to
testing and reporting of volatile organic compound emissions. No action can be
commenced until 60 days after the date of notice.

On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a
Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary
of findings resulting from a compliance investigation at the plant. The summary
includes allegations concerning compliance with certain recordkeeping and
reporting requirements, compliance with a referenced design heat input valve in
the Welsh permit, compliance with a fuel sulfur content limit, and compliance
with emission limits for sulfur dioxide.

SWEPCo has previously reported to the TCEQ, deviations related to the receipt of
off-specification fuel at Knox Lee, and the referenced recordkeeping and
reporting requirements and heat input valve at Welsh. We are preparing
additional responses to the Notice of Enforcement and the notice from the
special interest groups. Management is unable to predict the timing of any
future action by TCEQ or the special interest groups or the effect of such
actions on results of operations, financial condition or cash flows.

Carbon Dioxide Public Nuisance Claims
-------------------------------------

On July 21, 2004, attorneys general from eight states and the corporation
counsel for the City of New York filed an action in federal district court for
the Southern District of New York against AEP, AEPSC and four other unaffiliated
governmental and investor-owned electric utility systems. That same day, a
similar complaint was filed in the same court against the same defendants by the
Natural Resources Defense Council on behalf of two special interest groups. The
actions allege that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts associated
with global warming, and seek injunctive relief in the form of specific emission
reduction commitments from the defendants. Management believes the actions are
without merit and intends to vigorously defend against the claims.

Nuclear Decommissioning
-----------------------

As discussed in the 2003 Annual Report, decommissioning costs are accrued over
the service life of STP. The licenses to operate the two nuclear units at STP
expire in 2027 and 2028. TCC had estimated its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of approximately $8 million per year.

In May 2004, an updated decommissioning study was completed for STP. The study
estimates TCC's share of the decommissioning costs of STP to be $344 million in
nondiscounted 2004 dollars. As discussed in Note 7, TCC is in the process of
selling its ownership interest in STP to a non-affiliate, and upon completion of
the sale it is anticipated that TCC will no longer be obligated for nuclear
decommissioning liabilities associated with STP.

OPERATIONAL
-----------

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

We have agreements with Juniper Capital L.P. (Juniper) under which Juniper
constructed and financed a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and leased the Facility to us. We have
subleased the Facility to the Dow Chemical Company (Dow). The Facility is a
Dow-operated "qualifying cogeneration facility" for purposes of PURPA.
Commercial operation of the Facility as required by the agreements between
Juniper, AEP and Dow was achieved on March 18, 2004. The initial term of our
lease with Juniper (Juniper Lease) commenced on March 18, 2004 and terminates on
June 17, 2009. We may extend the term of the Juniper Lease for up to 30 years.
Our lease of the Facility is reported as an owned asset under a lease financing
transaction. Therefore, the asset and related liability for the debt and equity
of the facility are recorded on AEP's balance sheet.

Juniper is an unaffiliated limited partnership, formed to construct or otherwise
acquire real and personal property for lease to third parties, to manage
financial assets and to undertake other activities related to asset financing.

At June 30, 2004, Juniper's acquisition costs for the Facility totaled $520
million, and we estimate total costs for the completed Facility to be
approximately $525 million, funded through long-term debt financing of $494
million and equity of $31 million from investors with no relationship to AEP or
any of AEP's subsidiaries. For the initial 5-year lease term, the base lease
rental is equal to the interest on Juniper's debt financing at a variable rate
indexed to three-month LIBOR (1.61% as of June 30, 2004) plus 100 basis points,
plus a fixed return on Juniper's equity investment in the Facility and certain
other fixed amounts. Consequently, as LIBOR increases, the base rental payments
under the Juniper Lease will also increase.

The Facility is collateral for Juniper's debt financing. Due to the treatment of
the Facility as a financing of an owned asset, we recognized all of Juniper's
obligations as a liability of $520 million. Upon expiration of the lease, our
actual cash obligation could range from $0 to $415 million based on the fair
value of the assets at that time. However, if we default under the Juniper
Lease, our maximum cash payment could be as much as $525 million.

Dow uses a portion of the energy produced by the Facility and sells the excess
energy. OPCo has agreed to purchase up to approximately 800 MW of such excess
energy from Dow. Because the Facility is a major steam supply for Dow, Dow is
expected to operate the Facility at certain minimum levels, and OPCo is
obligated to purchase the energy generated at those minimum operating levels
(expected to be approximately 270 MW).

OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel
Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and
Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in
excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity,
energy and ancillary services to TEM pursuant to the PPA that TEM rejected as
non-conforming. Commercial operation for purposes of the PPA began April 2,
2004.

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

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

On March 26, 2004, OPCo requested that TEM provide assurances of performance of
its future obligations under the PPA, but TEM refused to do so. As indicated
above, OPCo also gave notice to TEM and declared April 2, 2004 as the
"Commercial Operations Date." Despite OPCo's prior tenders of replacement
electric power products to TEM beginning May 1, 2003 and despite OPCo's tender
of electric power products from the Facility to TEM beginning April 2, 2004, TEM
refused to accept and pay for them under the terms of the PPA. On April 5, 2004,
OPCo gave notice to TEM that OPCo (i) was suspending performance of its
obligations under PPA, (ii) would be seeking a declaration from the New York
federal court that the PPA has been terminated and (iii) would be pursuing
against TEM and Tractebel SA under the guaranty damages and the full termination
payment value of the PPA.

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

In 2002, certain of our subsidiaries filed claims against Enron and its
subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy
Court for the Southern District of New York. At the date of Enron's bankruptcy,
certain of our subsidiaries had open trading contracts and trading accounts
receivables and payables with Enron. In addition, on June 1, 2001, we purchased
HPL from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.

Bammel storage facility and HPL indemnification matters - In connection with the
2001 acquisition of HPL, we entered into a prepaid arrangement under which we
acquired exclusive rights to use and operate the underground Bammel gas storage
facility and appurtenant pipelines pursuant to an agreement with BAM Lease
Company. This exclusive right to use the referenced facility is for a term of 30
years, with a renewal right for another 20 years.

In January 2004, we filed an amended lawsuit against Enron and its subsidiaries
in the U.S. Bankruptcy Court claiming that Enron did not have the right to
reject the Bammel storage facility agreement or the cushion gas use agreement,
described below. In April 2004, AEP and Enron entered into a settlement
agreement under which we will acquire title to the Bammel gas storage facility
and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF)
of natural gas currently used as cushion gas for $115 million. AEP and Enron
will mutually release each other from all claims associated with the Bammel
facility, including our indemnity claims. The proposed settlement is subject to
Bankruptcy Court approval. The parties' respective trading claims and Bank of
America's (BOA) purported lien on approximately 55 BCF of natural gas in the
Bammel storage reservoir (as described below) are not covered by the settlement
agreement.

Right to use of cushion gas agreements - In connection with the 2001 acquisition
of HPL, we also entered into an agreement with BAM Lease Company, which grants
HPL the exclusive right to use approximately 65 BCF of cushion gas (the 10.5 BCF
and 55 BCF described in the preceding paragraph) required for the normal
operation of the Bammel gas storage facility. At the time of our acquisition of
HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an
agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the
time of our acquisition, Enron and the BOA Syndicate also released HPL from all
prior and future liabilities and obligations in connection with the financing
arrangement.

After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported
default by Enron under the terms of the financing arrangement. In July 2002, the
BOA Syndicate filed a lawsuit against HPL in the state court of Texas seeking a
declaratory judgment that the BOA Syndicate has a valid and enforceable security
interest in gas purportedly in the Bammel storage reservoir. In December 2003,
the Texas state court granted partial summary judgment in favor of the BOA
Syndicate. HPL appealed this decision. In June 2004, BOA filed an amended
petition in a separate lawsuit in Texas state court seeking to obtain possession
of up to 55 BCF of storage gas in the Bammel storage facility or its fair value.

In October 2003, AEP filed a lawsuit against BOA in the United States District
Court for the Southern District of Texas. BOA led a lending syndicate involving
the 1997 gas monetization that Enron and its subsidiaries undertook and the
leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit
asserts that BOA made misrepresentations and engaged in fraud to induce and
promote the stock sale of HPL, that BOA directly benefited from the sale of HPL
and that AEP undertook the stock purchase and entered into the Bammel storage
facility lease arrangement with Enron and the cushion gas arrangement with Enron
and BOA based on misrepresentations that BOA made about Enron's financial
condition that BOA knew or should have known were false including that the 1997
gas monetization did not contravene or constitute a default of any federal,
state, or local statute, rule, regulation, code or any law. In February 2004,
BOA filed a motion to dismiss this Texas federal lawsuit.

In February 2004, in connection with BOA's dispute, Enron filed Notices of
Rejection regarding the cushion gas exclusive right to use agreement and other
incidental agreements. We have objected to Enron's attempted rejection of these
agreements.

Commodity trading settlement disputes - In September 2003, Enron filed a
complaint in the Bankruptcy Court against AEPES challenging AEP's offsetting of
receivables and payables and related collateral across various Enron entities
and seeking payment of approximately $125 million plus interest in connection
with gas-related trading transactions. AEP has asserted its right to offset
trading payables owed to various Enron entities against trading receivables due
to several AEP subsidiaries. The parties are currently in non-binding
court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC
seeking approximately $93 million plus interest in connection with a transaction
for the sale and purchase of physical power among Enron, AEP and Allegheny
Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the
effects of the transaction. AEP believes it has several defenses to the claims
in the action being brought by Enron. The parties are currently in non-binding
court-sponsored mediation.

Enron bankruptcy summary - The amount expensed in prior years in connection with
the Enron bankruptcy was based on an analysis of contracts where AEP and Enron
entities are counterparties, the offsetting of receivables and payables, the
application of deposits from Enron entities and management's analysis of the HPL
related purchase contingencies and indemnifications. As noted above, Enron has
challenged our offsetting of receivables and payables and there is a dispute
regarding the cushion gas agreement. Management is unable to predict the outcome
of these lawsuits or their impact on our results of operations, cash flows or
financial condition.

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

Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider (REP),
filed a lawsuit in federal District Court in Corpus Christi, Texas, in July
2003, against us and four AEP subsidiaries, certain unaffiliated energy
companies and ERCOT. The action alleges violations of the Sherman Antitrust Act,
fraud, negligent misrepresentation, breach of fiduciary duty, breach of
contract, civil conspiracy and negligence. The allegations, not all of which are
made against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price spikes
requiring TCE to post additional collateral and ultimately forced it into
bankruptcy when it was unable to raise prices to its customers due to fixed
price contracts. The suit alleges over $500 million in damages for all
defendants and seeks recovery of damages, exemplary damages and court costs. Two
additional parties, Utility Choice, LLC and Cirro Energy Corporation, have
sought leave to intervene as plaintiffs asserting similar claims. We filed a
Motion to Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. We filed a Motion to Dismiss the amended complaint. In June 2004, the
Court dismissed all claims against the AEP companies. TCE has appealed the trial
court's decision to the United States Court of Appeals for the Fifth Circuit.

Energy Market Investigation
---------------------------

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

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. In January 2004, the CFTC issued a request for
documents and other information in connection with a CFTC investigation of
activities affecting the price of natural gas in the fall of 2003. We responded
to that request. The case is in the initial pleading stage with our response to
the complaint currently due on September 13, 2004. Although management is unable
to predict the outcome of this case, we recorded a provision in 2003 and the
action is not expected to have a material effect on future results of
operations, financial condition or cash flows. Management cannot predict what,
if any further action, any of these governmental agencies may take with respect
to these matters.

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

A FERC order issued in November 2001 on AEP's triennial market based wholesale
power rate authorization update required certain mitigation actions that AEP
would need to take for sales/purchases within its control area and required AEP
to post information on its website regarding its power system's status. As a
result of a request for rehearing filed by AEP and other market participants,
FERC issued an order delaying the effective date of the mitigation plan until
after a planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. In April 2004, the FERC issued two orders concerning
utilities' ability to sell wholesale electricity at market-based rates. In the
first order, the FERC adopted two new interim screens for assessing potential
generation market power of applicants for wholesale market based rates, and
described additional analyses and mitigation measures that could be presented if
an applicant does not pass one of these interim screens. In July 2004, the FERC
issued an order on rehearing affirming its conclusions in the April order and
directing AEP and two unaffiliated utilities to file generation market power
analyses within 30 days. In the second order, the FERC initiated a rulemaking to
consider whether the FERC's current methodology for determining whether a public
utility should be allowed to sell wholesale electricity at market-based rates
should be modified in any way. We plan to present evidence to demonstrate that
we do not possess market power in geographic areas where we sell wholesale
power.

6.  GUARANTEES
    ----------

There are certain immaterial liabilities recorded for guarantees entered into
subsequent to December 31, 2002 in accordance with FIN 45. There is no
collateral held in relation to any guarantees in excess of our ownership
percentages and there is no recourse to third parties in the event any
guarantees are drawn unless specified below.

LETTERS OF CREDIT
-----------------

We have entered into standby letters of credit (LOC) with third parties. These
LOCs cover gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits, debt service reserves and
credit enhancements for issued bonds. All of these LOCs were issued by us in the
ordinary course of business. At June 30, 2004, the maximum future payments for
all the LOCs were approximately $244 million with maturities ranging from July
2004 to January 2011. As the parent of various subsidiaries, we hold all assets
of the subsidiaries as collateral. There is no recourse to third parties in the
event these letters of credit are drawn.

We have guaranteed 50% of the principal and interest payments as well as 100% of
a Power Purchase Agreement (PPA) of the Fort Lupton, Colorado IPP (also known as
Thermo), of which we are a 50% owner. In the event Fort Lupton does not make the
required debt payments, we have a maximum future payment exposure of
approximately $7 million, which expires May 2008. In the event Fort Lupton is
unable to perform under its PPA agreement, we have a maximum future payment
exposure of approximately $15 million, which expires June 2019. We will be
released from this guarantee upon the anticipated sale of this IPP. See Note 7
regarding the sale of IPPs, of which Fort Lupton is included. Our exposure for
these payments will expire upon the sale of Fort Lupton in the third quarter of
2004.

We had a letter of credit for Orange Cogeneration, a cogeneration plant located
in Bartow, Florida, that expired upon its sale in July 2004. See Note 7.

GUARANTEES OF THIRD-PARTY OBLIGATIONS
-------------------------------------

CSW Energy and CSW International
--------------------------------

CSW Energy and CSW International, AEP subsidiaries, have guaranteed 50% of the
required debt service reserve of Sweeny Cogeneration L.P. (Sweeny), an IPP of
which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny
funding the debt reserve as a part of a financing. In the event that Sweeny does
not make the required debt payments, CSW Energy and CSW International have a
maximum future payment exposure of approximately $4 million, which expires June
2020.

AEP Utilities
-------------

AEP Utilities was released from its guarantee for Mulberry, a cogeneration plant
located in Bartow, Florida, when it was sold in July 2004. See Note 7.

SWEPCo
------

In connection with reducing the cost of the lignite mining contract for its
Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain conditions, to
assume the capital lease obligations and term loan payments of the mining
contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under
any of these agreements, SWEPCo's total future maximum payment exposure is
approximately $51 million with maturity dates ranging from June 2005 to February
2012.

As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, SWEPCo has agreed to provide guarantees of mine
reclamation in the amount of approximately $85 million. Since SWEPCo uses
self-bonding, the guarantee provides for SWEPCo to commit to use its resources
to complete the reclamation in the event the work is not completed by a third
party miner. At June 30, 2004, 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.

As of July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46.
SWEPCo does not have an ownership interest in Sabine.

INDEMNIFICATIONS AND OTHER GUARANTEES
-------------------------------------

Contracts
---------

We entered into several types of contracts which require indemnifications.
Typically these contracts include, but are not limited to, sale agreements,
lease agreements, purchase agreements and financing agreements. Generally these
agreements may include, but are not limited to, indemnifications around certain
tax, contractual and environmental matters. With respect to sale agreements, our
exposure generally does not exceed the sale price. We cannot estimate the
maximum potential exposure for any of these indemnifications entered into prior
to December 31, 2002 due to the uncertainty of future events. In 2003 and during
the first six months of 2004, we entered into several sale agreements. These
sale agreements include indemnifications with a maximum exposure of
approximately $258 million. There are no material liabilities recorded for any
indemnifications entered into during 2003 or the first six months 2004. There
are no liabilities recorded for any indemnifications entered prior to December
31, 2002.

Master Operating Lease
----------------------

We lease certain equipment under a master operating lease. Under the lease
agreement, the lessor is guaranteed to receive up to 87% of the unamortized
balance of the equipment at the end of the lease term. If the fair market value
of the leased equipment is below the unamortized balance at the end of the lease
term, we have committed to pay the difference between the fair market value and
the unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At June 30, 2004, the maximum potential loss for these
lease agreements was approximately $35 million ($23 million, net of tax)
assuming the fair market value of the equipment is zero at the end of the lease
term.

Railcar Lease
-------------

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

Under the lease agreement, the lessor is guaranteed that the sale proceeds under
a return-and-sale option will equal at least a lessee obligation amount
specified in the lease, which declines over the term from approximately 86% to
77% of the projected fair market value of the equipment. At June 30, 2004, 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 terms to an
unaffiliated company under an operating lease. The sublessee has recently
renewed for an additional year and may renew the lease for up to three more
additional one-year terms.


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

DISPOSITION COMPLETED DURING FIRST QUARTER 2004
-----------------------------------------------

Pushan Power Plant (Investments - Other segment)
------------------------------------------------

In the fourth quarter of 2002, we began active negotiations to sell our interest
in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest
partner and a purchase and sale agreement was signed in the fourth quarter of
2003. The sale was completed in March 2004 for $60.7 million. An estimated
pre-tax loss on disposal of $20 million pre-tax ($13 million after-tax) was
recorded in December 2002, based on an indicative price expression at that time,
and was classified in Discontinued Operations. The effect of the sale on the
first quarter 2004 results of operations was not significant.

Results of operations of Pushan have been reclassified as Discontinued
Operations. The assets and liabilities of Pushan were classified on our
Consolidated Balance Sheets as held for sale until the sale was complete.
Beginning with our first quarter 2004 financial statements, the assets and
liabilities of Pushan are shown as Assets of Discontinued Operations and
Liabilities of Discontinued Operations for all periods presented.

DISPOSITIONS COMPLETED DURING SECOND QUARTER 2004
-------------------------------------------------

LIG Pipeline Company and its Subsidiaries (Investments - Gas Operations segment)
--------------------------------------------------------------------------------

In February 2004, we signed an agreement to sell LIG Pipeline Company, which
includes approximately 2,000 miles of natural gas gathering and transmission
pipelines in Louisiana and five gas processing facilities that straddle the
system. The sale of LIG Pipeline Company and its assets for $76.2 million was
completed in April 2004. The effect of the sale on the second quarter 2004
results of operations was not significant.

Results of operations of LIG Pipeline Company were reclassified as of December
31, 2003 as Discontinued Operations. The assets and liabilities of LIG Pipeline
Company were classified on our Balance Sheet as held for sale until the sale was
complete. Beginning with our second quarter 2004 financial statements, the
assets and liabilities of LIG Pipeline Company are shown as Assets of
Discontinued Operations and Liabilities of Discontinued Operations for all
periods presented.

See Louisiana Intrastate Gas (LIG) in Discontinued Operations section of this
note for previous impairments taken on the LIG assets and information regarding
remaining LIG assets still held for sale.

AEP Coal (Investments - Other segment)
--------------------------------------

In 2003, as a result of management's decision to exit our non-core businesses,
we retained an advisor to facilitate the sale of AEP Coal. In March 2004, an
agreement was reached to sell assets, exclusive of certain reserves and related
liabilities, of the mining operations of AEP Coal. AEP received approximately
$8.8 million cash and the buyer assumed an additional $11.1 million in future
reclamation liability. AEP has retained an estimated $36.7 million in future
reclamation liabilities. The sale closed in April 2004 and the effect of the
sale on second quarter 2004 results of operations was not significant. The
assets and liabilities of AEP Coal that were held for sale have been included in
Assets Held for Sale and Liabilities Held for Sale in our Consolidated Balance
Sheets at December 31, 2003.

DISPOSITIONS COMPLETED OR SCHEDULED TO BE COMPLETED DURING SECOND HALF 2004
---------------------------------------------------------------------------

Texas Plants (Utility Operations segment)
-----------------------------------------

In December 2002, TCC filed a plan of divestiture with the PUCT proposing to
sell all of its power generation assets, including the eight gas-fired
generating plants that were either deactivated or designated as "reliability
must run" status.

During the fourth quarter of 2003, after receiving bids from interested buyers,
we recorded a $938 million impairment loss and changed the classification of the
plant assets from plant in service to Assets Held for Sale. In accordance with
Texas legislation, the $938 million impairment was offset by the establishment
of a regulatory asset, which is expected to be recovered through a wires charge,
subject to the final outcome of the 2004 Texas true-up proceeding. As a result
of the 2004 true-up proceeding, if we are unable to recover all or a portion of
our requested costs (see Note 4), any unrecovered costs could have a material
adverse effect on our results of operations, cash flows and possibly financial
condition.

During early 2004, we signed agreements to sell all of our TCC generating
assets, at prices which approximate book value after considering the impairment
charge described above. As a result, we do not expect these pending asset sales,
described below, to have a significant effect on our future results of
operations, except in the case that our true-up proceedings, as described above,
do not allow for recovery of our stranded costs.

      Oklaunion Power Station
      -----------------------
      In April 2004, we signed an agreement to sell TCC's 7.81 percent share of
      Oklaunion Power Station for approximately $43 million (subject to closing
      adjustments) to an unrelated party. In May 2004, we received notice from
      the two co-owners of the Oklaunion Power Station, announcing their
      decision to exercise their right of first refusal, with terms similar to
      the original agreement. The sale is currently being challenged by the
      unrelated party with which we entered into the original sales agreement.
      The unrelated party alleges that one of two co-owners has exceeded its
      legal authority and has requested that the court declare the one
      co-owner's exercise of its right of first refusal void. The unrelated
      party further argues that the second of the two co-owner's exercise of its
      right of first refusal is not timely and invalid. We expect that this
      legal issue will be resolved and that the planned sale will close by the
      end of 2004.

      South Texas Project
      -------------------
      In February 2004, we signed an agreement to sell TCC's 25.2 percent share
      of the South Texas Project (STP) nuclear plant for approximately $333
      million, subject to closing adjustments. In June 2004, we received notice
      from co-owners of their decisions to exercise their rights of first
      refusal, with terms similar to the original agreement. We expect the sale
      to close before the end of 2004 subject to necessary regulatory approval.

      TCC Generation Assets
      ---------------------
      In March 2004, we signed an agreement to sell our remaining generating
      assets within TCC, including eight natural gas plants, one coal-fired
      plant and one hydro plant to a non-related joint venture. The sale was
      completed in July 2004 for approximately $425 million, net of adjustments.
      The sale did not have a significant effect on our results of operations
      during the second quarter 2004.

Independent Power Producers (Investments - Other segment)
---------------------------------------------------------

During the third quarter of 2003, we initiated an effort to sell four domestic
Independent Power Producer (IPP) investments accounted for under the equity
method (two located in Colorado and two located in Florida). Our two Colorado
investments include a 47.75 percent interest in Brush II, a 68-megawatt,
gas-fired, combined cycle, cogeneration plant in Brush, Colorado and a 50
percent interest in Thermo, a 272-megawatt, gas-fired, combined cycle,
cogeneration plant located in Ft. Lupton, Colorado. Our two Florida investments
include a 46.25 percent interest in Mulberry, a 120-megawatt, gas-fired,
combined cycle, cogeneration plant located in Bartow, Florida and a 50 percent
interest in Orange, a 103-megawatt, gas-fired, combined cycle, cogeneration
plant located in Bartow, Florida. In accordance with accounting principles
generally accepted in the United States of America, we were required to measure
the impairment of each of these four investments individually. Based on
indicative bids, it was determined that an other than temporary impairment
existed on the two equity method investments located in Colorado. The $70.0
million pre-tax ($45.5 million, net of tax) impairment recorded in September
2003 was the result of the measurement of fair value that was triggered by our
recent decision to sell the assets. This loss of investment value was included
in Investment Value Losses on our Consolidated Statements of Operations for the
year ended December 31, 2003.

In March 2004, we entered into an agreement to sell the four domestic IPP
investments for a sales price of $156 million, subject to closing adjustments.
An additional pre-tax impairment of $1.6 million was recorded in June 2004
(recorded to Other Income (Expense), Net) to decrease the carrying value of the
Colorado plant investments to their estimated sales price, less selling
expenses. We closed on the sale of the two Florida investments and the Brush II
plant in Colorado in July 2004, resulting in a pre-tax gain of approximately
$100 million, generated primarily from the sale of the two Florida IPPs which
were not originally impaired. The gain was recorded during July 2004. The sale
of the Ft. Lupton, Colorado plant is awaiting Federal Energy Regulatory
Commission approval and is expected to close during the third quarter 2004, with
no significant effect on results of operations during the third quarter.

U.K. Generation (Investments - UK Operations segment)
-----------------------------------------------------

In December 2001, we acquired two coal-fired generation plants (U.K. Generation)
in the U.K. for a cash payment of $942.3 million and assumption of certain
liabilities. Since December 2001, we also made additional equity contributions
to fund our UK Operations. Subsequently and continuing through 2002, wholesale
U.K. electric power prices declined sharply as a result of domestic
over-capacity and static demand. External industry forecasts and our own
projections made during the fourth quarter of 2002 indicated that this situation
may extend many years into the future. As a result, the U.K. Generation fixed
asset carrying value at year-end 2002 was substantially impaired. A December
2002, probability-weighted discounted cash flow analysis of the fair value of
our U.K. Generation indicated a 2002 pre-tax impairment loss of $548.7 million
($414 million after-tax). This impairment loss is included in 2002 Discontinued
Operations on our Consolidated Statements of Operations.

In the fourth quarter of 2003, the U.K. generation plants were determined to be
non-core assets and management engaged an investment advisor to assist in
determining the best methodology to exit the U.K. business. An information
memorandum was distributed for the sale of our U.K. generation plants. Based on
information received, we recorded a $577 million pre-tax charge ($375
after-tax), including asset impairments of $420.7 million during the fourth
quarter of 2003 to write down the value of the assets to their estimated
realizable value. Additional charges of $156.7 million pre-tax were also
recorded in December 2003 including $122.2 million related to the net loss on
certain cash flow hedges previously recorded in Accumulated Other Comprehensive
Income (Loss) that have been reclassified into earnings as a result of
management's determination that the hedged event is no longer probable of
occurring and $34.5 million related to a first quarter 2004 sale of certain
power contracts. The assets and liabilities of U.K. Generation have been
classified as held for sale on our Consolidated Balance Sheets and the results
of operations are included in Discontinued Operations on our Consolidated
Statements of Operations.

In July 2004, we completed the sale of substantially all operations and assets
within the U.K. The sale included our two coal-fired generation plants
(Fiddler's Ferry and Ferrybridge) that were held-for-sale as described above,
related coal assets, and a number of related commodities contracts for
approximately $456 million. We are still determining the final impact from the
sale on our third quarter results of operations. Although the final sales price
will be subject to closing adjustments, expected to be determined during the
third quarter 2004, we believe that a gain on sale, which would be included in
discontinued operations, may result.

Excess Real Estate (Investments - Other segment)
------------------------------------------------

In the fourth quarter of 2002, we began to market an under-utilized office
building in Dallas, TX obtained through our merger with CSW in June 2000. One
prospective buyer executed an option to purchase the building. Sale of the
facility was projected by second quarter 2003 and an estimated 2002 pre-tax loss
on disposal of $15.7 million was recorded, based on the option sale price. The
estimated loss was included in Asset Impairments on AEP's Consolidated
Statements of Operations in 2002. In December 2003, we recorded an additional
pre-tax impairment of $6 million recorded in Maintenance and Other Operation on
our Consolidated Statements of Operations. The original prospective buyer did
not complete their purchase of the building by the end of 2003, and thus, the
asset no longer qualified for held for sale status. The building was then
reclassified to held and used status as of December 31, 2003.

In June 2004, we entered into negotiations to sell the Dallas office building.
This resulted in the asset again being classified as held for sale in the second
quarter of 2004. An additional pre-tax impairment of $2.5 million was recorded
to Maintenance and Other Operation expense during the second quarter of 2004 to
write down the value of the office building to the current estimated sales
price, less estimated selling expenses. The property asset of $9.5 million at
June 30, 2004 and $12.0 million at December 31, 2003 has been classified on
AEP's Consolidated Balance Sheets as held for sale. Although the negotiations
entered into in June 2004 did not yield a final signed purchase agreement,
active efforts to sell the building continue and we do not expect the sale to
have a significant effect on our results of operations.

DISCONTINUED OPERATIONS
-----------------------

Management periodically assesses the overall AEP business model and makes
decisions regarding our continued support and funding of our various businesses
and operations. When it is determined that we will seek to exit a particular
business or activity and we have met the accounting requirements for
reclassification, we will reclassify the operations of those businesses or
operations as discontinued operations. The assets and liabilities of these
discontinued operations are classified as Assets and Liabilities Held for Sale
until the time that they are sold. At the time they are sold they are
reclassified to Assets and Liabilities of Discontinued Operations on the
Consolidated Balance Sheets for all periods presented. Assets and liabilities
that are held for sale, but do not qualify as a discontinued operations are
reflected as Assets and Liabilities Held for Sale both while they are held for
sale and after they have been sold, for all periods presented.

Certain of our operations were determined to be discontinued operations and have
been classified as such for all periods presented. Results of operations of
these businesses have been reclassified for the three and six month periods
ended June 30, 2004 and 2003, as shown in the following table:

<TABLE>
<CAPTION>

     For the three months ended June 30, 2004 and 2003:
                                                                           Pushan
                                                                           Power                    U.K.
                                                             Eastex        Plant       LIG       Generation      Total
                                                             ------        ------      ---       ----------      -----
                                                                                  (in millions)
     <C>                                                       <C>          <C>        <C>          <C>           <C>
     2004 Revenue                                              $-           $-          $4          $34           $38
     2004 Pretax Income (Loss)                                  -            -           2          (80)          (78)
     2004 Income (Loss) After-Tax                               -           (1)          2          (52)          (51)

     2003 Revenue                                              15           12         150           61           238
     2003 Pretax Income (Loss)                                 (9)           -           3            4            (2)
     2003 Income (Loss) After-Tax                              (7)           -           1            4            (2)

</TABLE>
<TABLE>
<CAPTION>

     For the six months ended June 30, 2004 and 2003:
                                                                           Pushan
                                                                           Power                    U.K.
                                                             Eastex        Plant       LIG       Generation      Total
                                                             ------        ------      ---       ----------      -----
                                                                                  (in millions)
     <C>                                                      <C>          <C>        <C>           <C>          <C>
     2004 Revenue                                              $-          $10        $164          $75          $249
     2004 Pretax Income (Loss)                                  -            9           1          (99)          (89)
     2004 Income (Loss) After-Tax                               -            5           1          (64)          (58)

     2003 Revenue                                              46           27         353          112           538
     2003 Pretax Income (Loss)                                (23)           -           6          (36)          (53)
     2003 Income (Loss) After-Tax                             (15)           -           4          (37)          (48)

</TABLE>

<TABLE>
<CAPTION>

Assets and liabilities of discontinued operations have been reclassified as follows:

                                                                Pushan Power         LIG (excluding
                                                                   Plant            Jefferson Island)      Total
                                                                ------------        -----------------      -----
                                                                                     (in millions)
    As of December 31, 2003
    -----------------------
    <C>                                                             <C>                   <C>               <C>
    Current Assets                                                   $24                   $49               $73
    Property, Plant and Equipment, Net                               142                   109               251
    Goodwill                                                           -                     1                 1
    Other                                                              -                     8                 8
                                                                    -----                 -----             -----
    Total Assets of Discontinued Operations                         $166                  $167              $333
                                                                    =====                 =====             =====

    Current Risk Management Liabilities                               $-                   $15               $15
    Current Liabilities                                               26                    42                68
    Long-term Debt                                                    20                     -                20
    Deferred Credits and Other                                        57                     6                63
                                                                    -----                 -----             -----
    Total Liabilities of Discontinued Operations                    $103                   $63              $166
                                                                    =====                 =====             =====
</TABLE>


Pushan Power Plant (Investments - Other segment)
------------------------------------------------

See Pushan Power Plant section under Dispositions Completed During First Quarter
2004 for information regarding the sale of Pushan Power Plant.

Louisiana Intrastate Gas (LIG) (Investments - Gas Operations segment)
---------------------------------------------------------------------

As a result of our 2003 decision to exit our non-core businesses, we actively
marketed LIG Pipeline Company (gas pipeline and processing operations) and
Jefferson Island Storage & Hub, L.L.C. (JISH) (gas storage) together as a
combined operation. For the year ended December 31, 2003, LIG's assets
(including those of JISH) were classified as held for sale and their operations
where shown under Discontinued Operations. In January 2004, a decision was made
to sell LIG's pipeline and processing assets separate from LIG's gas storage
assets. After receiving and analyzing initial bids during the fourth quarter of
2003, we recorded a $133.9 million pre-tax ($99 million after-tax) impairment
loss; of this loss, $128.9 million pre-tax relates to the impairment of goodwill
and $5 million pre-tax relates to other charges. In February 2004, we signed a
definitive agreement to sell LIG Pipeline Company, which owned all of the
pipeline and processing assets of LIG. The sale was completed in April 2004 and
the impact on results of operations in the second quarter of 2004 was not
significant (see LIG Pipeline Company and its Subsidiaries in Dispositions
Completed During Second Quarter 2004 for additional information). Management
continues its efforts to market JISH. The assets and liabilities of LIG (not
including JISH) are classified as Assets of Discontinued Operations and
Liabilities of Discontinued Operations on our Consolidated Balance Sheets and
the results of operations (including the above-mentioned impairments and other
related charges) are classified in Discontinued Operations in our Consolidated
Statements of Operations. The gas storage assets of JISH remain held for sale as
of June 30, 2004. It is anticipated that the sale of JISH will take place by the
end of the year, and that it will not have a significant impact on our results
of operation's.

U.K. Generation
---------------

See U.K. Generation section under Dispositions Completed or Scheduled to be
Completed During Second Half 2004 for information regarding the sale of U.K.
Generation assets in July 2004.

ASSETS HELD FOR SALE
--------------------

The assets and liabilities of the entities held for sale at June 30, 2004 and
December 31, 2003 are as follows:

<TABLE>
<CAPTION>


                                              U.K.           Texas     Excess Real    Jefferson
June 30, 2004                              Generation        Plants      Estate        Island        Total
-------------                              ----------        ------    -----------    ---------      -----
                                                                      (in millions)
<C>                                            <C>          <C>            <C>          <C>        <C>
Assets:
-------
Current Risk Management Assets                 $251             $-          $-           $-          $251
Other Current Assets                            372             58           -            3           433
Property, Plant and Equipment, Net              115            796          10           63           984
Regulatory Assets                                 -             51           -            -            51
Decommissioning Trusts                            -            132           -            -           132
Goodwill                                          -              -           -           14            14
Long-term Risk Management Assets                 56              -           -            -            56
Other                                           117              -           -           17           134
                                               -----        -------        ----         ----       -------
Total Assets Held for Sale                     $911         $1,037         $10          $97        $2,055
                                               =====        =======        ====         ====       =======
Liabilities:
------------
Current Risk Management Liabilities            $276             $-          $-           $-          $276
Other Current Liabilities                       156              -           -            2           158
Long-term Risk Management Liabilities            49              -           -            -            49
Regulatory Liabilities                            -              9           -            -             9
Asset Retirement Obligations                     45            227           -            -           272
Employee Pension Obligations                     10              -           -            -            10
Deferred Credits and Other                        1              -           -            -             1
                                               -----        -------        ----         ----       -------
Total Liabilities Held for Sale                $537           $236          $-           $2          $775
                                               =====        =======        ====         ====       =======
</TABLE>
<TABLE>
<CAPTION>


                                    AEP       U.K.           Texas     Excess Real    Jefferson
December 31, 2003                   Coal   Generation        Plants      Estate        Island        Total
-----------------                   ----   ----------        ------    -----------    ---------      -----
                                                               (in millions)
<C>                                 <C>      <C>            <C>            <C>          <C>         <C>
Assets:
-------
Current Risk Management Assets       $-        $560             $-          $-           $-          $560
Other Current Assets                  6         685             57           -            1           749
Property, Plant and Equipment, Net   13          99            797          12           62           983
Regulatory Assets                     -           -             49           -            -            49
Decommissioning Trusts                -           -            125           -            -           125
Goodwill                              -           -              -           -           14            14
Long-term Risk Management Assets      -         274              -           -            -           274
Other                                 -           6              -           -            1             7
                                    ----     -------        -------        ----         ----       -------
Total Assets Held for Sale          $19      $1,624         $1,028         $12          $78        $2,761
                                    ====     =======        =======        ====         ====       =======
Liabilities:
------------
Current Risk Management
 Liabilities                         $-        $767             $-          $-           $-          $767
Other Current Liabilities             -         221              -           -            4           225
Long-term Risk Management
 Liabilities                          -         435              -           -            -           435
Regulatory Liabilities                -           -              9           -            -             9
Asset Retirement Obligations         11          29            219           -            -           259
Employee Pension Obligations          -          12              -           -            -            12
Deferred Credits and Other            3           -              -           -            -             3
                                    ----     -------        -------        ----         ----       -------
Total Liabilities Held for Sale     $14      $1,464           $228          $-           $4        $1,710
                                    ====     =======        =======        ====         ====       =======
</TABLE>

8.  BENEFIT PLANS
    -------------

Components of Net Periodic Benefit Costs
----------------------------------------

The following table provides the components of our net periodic benefit cost
(credit) for the following plans for the three and six months ended June 30,
2004 and 2003:

<TABLE>
<CAPTION>
                                                                                                       U.S.
                                                                 U.S.                           Other Postretirement
Three Months ended June 30, 2004 and 2003:                  Pension Plans                          Benefit Plans
------------------------------------------              ---------------------                 -----------------------
                                                        2004             2003                 2004               2003
                                                        ----             ----                 ----               ----
                                                                               (in millions)
<C>                                                     <C>               <C>                  <C>                <C>
Service Cost                                             $21              $20                  $10                $11
Interest Cost                                             57               59                   30                 33
Expected Return on Plan Assets                           (73)             (80)                 (20)               (17)
Amortization of Transition
  (Asset) Obligation                                       1               (2)                   7                  6
Amortization of Net Actuarial Loss                         4                3                    9                 13
                                                        -----            -----                 ----               ----
Net Periodic Benefit Cost                                $10               $-                  $36                $46
                                                        =====            =====                 ====               ====

</TABLE>
<TABLE>
<CAPTION>
                                                                                                        U.S.
                                                                  U.S.                          Other Postretirement
Six Months ended June 30, 2004 and 2003:                     Pension Plans                         Benefit Plans
----------------------------------------                ---------------------                 ----------------------
                                                        2004             2003                 2004               2003
                                                        ----             ----                 ----               ----
                                                                               (in millions)
<C>                                                     <C>              <C>                   <C>                <C>
Service Cost                                             $43              $40                  $20                $21
Interest Cost                                            114              117                   59                 65
Expected Return on Plan Assets                          (146)            (159)                 (41)               (32)
Amortization of Transition
  (Asset) Obligation                                       1               (4)                  14                 14
Amortization of Net Actuarial Loss                         8                5                   18                 26
                                                        -----            -----                 ----               ----
Net Periodic Benefit Cost (Credit)                       $20              $(1)                 $70                $94
                                                        =====            =====                 ====               ====

In accordance with our implementation of FASB Staff Position FAS 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003," as discussed in Note 2, accounting for the Medicare
subsidy reduced expected 2004 postretirement benefit cost by $29 million. As a result, expected cash flows for 2004 employer
contributions to U.S. other postretirement benefit plans have been reduced by $29 million from the $180 million disclosed at
December 31, 2003. Including an additional $19 million reduction related to refining earlier estimates, we currently expect to
contribute approximately $132 million to our U.S. other postretirement benefit plans during 2004.
</TABLE>

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

Investments - Gas Operations*
-----------------------------
 o  Gas pipeline and storage services

Investments - UK Operations**
-----------------------------
 o  International generation of electricity for sale to wholesale customers
 o  Coal procurement and transportation to AEP's U.K. plants

Investments - Other
-------------------
 o  Bulk commodity barging operations, windfarms, independent power producers
    and other energy supply businesses

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

The tables below present segment income statement information for the three and
six months ended June 30, 2004 and 2003 and balance sheet information as of June
30, 2004 and December 31, 2003. These amounts include certain estimates and
allocations where necessary. Prior year amounts have been reclassified to
conform to the current year's presentation.
<TABLE>
<CAPTION>

                                                           Investments
                                                  ---------------------------------
                                   Utility           Gas           UK                    All         Reconciling
                                  Operations      Operations    Operations    Other     Other*       Adjustments   Consolidated
                                  ----------      ----------    ----------    -----     ------       -----------   ------------
                                                                          (in millions)
Three Months Ended June 30, 2004
--------------------------------
<C>                               <C>              <C>             <C>        <C>        <C>            <C>            <C>
Revenues from:
  External Customers               $2,501            $777            $-          $90          $-              $-        $3,368
  Other Operating Segments             43              40             -           19          (2)           (100)            -
  Total Revenues                    2,544             817             -          109          (2)           (100)        3,368
Income (Loss) Before
  Discontinued Operations and
  Cumulative Effect of
  Accounting Changes                  183              (4)            -           (3)        (25)              -           151
Discontinued Operations, Net
  of Tax                                -               2           (52)          (1)          -               -           (51)
Net Income (Loss)                     183              (2)          (52)          (4)        (25)              -           100

As of June 30, 2004
-------------------
Total Assets                      $31,235          $2,207          $800       $1,519     $13,090        $(13,003)      $35,848
Assets Held for Sale and
  Assets of Discontinued
  Operations                        1,037              97           911           10           -               -         2,055

*  All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
   company subsidiary, which provides services at cost to the other operating segments.
</TABLE>
<TABLE>
<CAPTION>

                                                           Investments
                                                  ---------------------------------
                                   Utility           Gas           UK                    All         Reconciling
                                  Operations      Operations    Operations    Other     Other*       Adjustments   Consolidated
                                  ----------      ----------    ----------    -----     ------       -----------   ------------
                                                                          (in millions)
Three Months Ended June 30, 2003
--------------------------------
<C>                               <C>              <C>           <C>          <C>        <C>            <C>            <C>
Revenues from:
  External Customers               $2,672            $638            $-         $140          $-              $-        $3,450
  Other Operating Segments             (7)             37             -           28           4             (62)            -
  Total Revenues                    2,665             675             -          168           4             (62)        3,450
Income (Loss) Before
  Discontinued Operations
  and Cumulative Effect of
  Accounting Changes                  225             (25)            -          (20)         (3)              -           177
Discontinued Operations,
  Net of Tax                            -               1             4           (7)          -               -            (2)
Net Income (Loss)                     225             (24)            4          (27)         (3)              -           175

As of December 31, 2003
-----------------------
Total Assets                      $30,816          $2,405        $1,705       $1,697     $14,925        $(14,804)      $36,744
Assets Held for Sale and
  Assets of Discontinued
  Operations                        1,028             245         1,624          185          12               -         3,094

*  All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
   company subsidiary, which provides services at cost to the other operating segments.
</TABLE>
<TABLE>
<CAPTION>

                                                           Investments
                                                  ---------------------------------
                                   Utility           Gas           UK                    All         Reconciling
                                  Operations      Operations    Operations    Other     Other*       Adjustments   Consolidated
                                  ----------      ----------    ----------    -----     ------       -----------   ------------
                                                                          (in millions)
Six Months Ended June 30, 2004
------------------------------
<C>                               <C>              <C>             <C>          <C>      <C>            <C>            <C>
Revenues from:
  External Customers               $5,080          $1,429            $-         $200          $-              $-        $6,709
  Other Operating Segments             69              39             -           50           4            (162)            -
  Total Revenues                    5,149           1,468             -          250           4            (162)        6,709
Income (Loss) Before
  Discontinued Operations and
  Cumulative Effect of
  Accounting Changes                  486             (13)            -            1         (34)              -           440
Discontinued Operations,
  Net of Tax                            -               1           (64)           5           -               -           (58)
Net Income (Loss)                     486             (12)          (64)           6         (34)              -           382

As of June 30, 2004
-------------------
Total Assets                      $31,235          $2,207          $800       $1,519     $13,090        $(13,003)      $35,848
Assets Held for Sale and
  Assets of Discontinued
  Operations                        1,037              97           911           10           -               -         2,055

*  All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
   company subsidiary, which provides services at cost to the other operating segments.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>
                                                           Investments
                                                  ---------------------------------
                                   Utility           Gas           UK                    All         Reconciling
                                  Operations      Operations    Operations    Other     Other*       Adjustments   Consolidated
                                  ----------      ----------    ----------    -----     ------       -----------   ------------
                                                                          (in millions)
Six Months Ended June 30, 2003
------------------------------
<C>                               <C>              <C>           <C>          <C>        <C>            <C>              <C>
Revenues from:
  External Customers               $5,359          $1,571            $-         $305          $-              $-        $7,235
  Other Operating Segments             12              52             -           43           7            (114)            -
  Total Revenues                    5,371           1,623             -          348           7            (114)        7,235
Income (Loss) Before
  Discontinued Operations
  and Cumulative Effect of
  Accounting Changes                  531             (43)            -            -         (18)              -           470
Discontinued Operations,
  Net of Tax                            -               4           (37)         (15)          -               -           (48)
Cumulative Effect of
  Accounting Changes,
  Net of Tax                          236             (22)          (21)           -           -               -           193
Net Income (Loss)                     767             (61)          (58)         (15)        (18)              -           615

As of December 31, 2003
-----------------------
Total Assets                      $30,816          $2,405        $1,705       $1,697     $14,925        $(14,804)      $36,744
Assets Held for Sale and
  Assets of Discontinued
  Operations                        1,028             245         1,624          185          12               -         3,094

* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
  company subsidiary, which provides services at cost to the other operating segments.
</TABLE>

10.  FINANCING ACTIVITIES
     --------------------

<TABLE>
<CAPTION>

Long-term debt and other securities issued and retired during the first six months of 2004 are shown in the table below.

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

Issuances:
---------

<C>                         <C>                                          <C>                   <C>                <C>
CSPCo                       Installment Purchase Contracts                $44                  Variable             2038
OPCo                        Financing Obligation                            6                    5.77               2024
PSO                         Installment Purchase Contracts                 34                  Variable             2014
PSO                         Senior Unsecured Notes                         50                    4.70               2009
SWEPCo                      Installment Purchase Contracts                 54                  Variable             2019
SWEPCo                      Installment Purchase Contracts                 41                  Variable             2011
SWEPCo                      Financing Obligation                           14                    5.77               2024

Non-Registrant:
  AEP Subsidiary            Notes Payable                                  23                  Variable             2009
  AEP Subsidiaries          Other Debt                                      2                  Variable            Various
                                                                         -----
Total Issuances                                                          $268 (a)
                                                                         =====

</TABLE>
<TABLE>
<CAPTION>

(a) Amount indicated on statement of cash flows of $263 million is net of issuance costs.

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

<C>                         <C>                                        <C>                      <C>                 <C>
AEP                         Senior Unsecured Notes                        $57                    5.25               2015
AEP                         Senior Unsecured Notes                         10                    5.375              2010
APCo                        First Mortgage Bonds                           45                    7.125              2024
APCo                        Installment Purchase Contracts                 40                    5.45               2019
CSPCo                       First Mortgage Bonds                           11                    7.60               2024
CSPCo                       Installment Purchase Contracts                 44                    6.25               2020
I&M                         First Mortgage Bonds                           30                    7.20               2024
I&M                         First Mortgage Bonds                           25                    7.50               2024
OPCo                        Installment Purchase Contracts                 50                    6.85               2022
OPCo                        Notes Payable                                   2                    6.27               2009
OPCo                        Notes Payable                                   3                    6.81               2008
OPCo                        First Mortgage Bonds                           10                    7.30               2024
OPCo                        Senior Unsecured Notes                        140                    7.375              2038
PSO                         Notes Payable to Trust                         77                    8.00               2037
PSO                         Installment Purchase Contracts                 34                    4.875              2014
SWEPCo                      Installment Purchase Contracts                 12                    6.90               2004
SWEPCo                      Installment Purchase Contracts                 12                    6.00               2008
SWEPCo                      Installment Purchase Contracts                 17                    8.20               2011
SWEPCo                      Installment Purchase Contracts                 54                    7.60               2019
SWEPCo                      First Mortgage Bonds                           80                    6.875              2025
SWEPCo                      First Mortgage Bonds                           40                    7.75               2004
SWEPCo                      Notes Payable                                   3                    4.47               2011
SWEPCo                      Notes Payable                                   2                   Variable            2008
TCC                         First Mortgage Bonds                            6                    6.625              2005
TCC                         Securitization Bonds                           29                    3.54               2005
TNC                         First Mortgage Bonds                           24                    6.125              2004

Non-Registrant:
  AEP Subsidiaries          Notes Payable                                  40                    6.73               2004
  AEP Subsidiaries          Notes Payable and Other Debt                  114                   Variable          2007-2017
                                                                       -------
Total Retirements                                                      $1,011 (b)
                                                                       =======

(b)  Amount indicated on statement of cash flows of $986 million does not include $25 million related to retirement of debt of a
     discontinued operation.

</TABLE>
<TABLE>
<CAPTION>


                                                                       Principal              Interest
Company                        Type of Debt                             Amount                 Rate              Due Date
-------                        ------------                            ---------              --------           --------
                                                                     (in millions)              (%)
Defeasance:
----------
<C>                         <C>                                          <C>                     <C>                <C>

TCC                         First Mortgage Bonds                          $27                    7.25               2004
TCC                         First Mortgage Bonds                           66                    6.625              2005
TCC                         First Mortgage Bonds                           19                    7.125              2008
                                                                         -----
Total Defeased                                                           $112  (c)
                                                                         =====

(c)   Trust fund assets for defeasance of First Mortgage Bonds of $103 million are included in Other Cash Deposits and $22 million
      in Other Non-current Assets in the Consolidated Balance Sheets at June 30, 2004. Trust fund assets are restricted for
      exclusive use in retiring the First Mortgage Bonds.

</TABLE>

<PAGE>








                             AEP GENERATING COMPANY









<PAGE>


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

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

Operating revenues are derived from the sale of Rockport Plant energy and
capacity to I&M and KPCo pursuant to FERC approved long-term unit power
agreements. The unit power agreements provide for a FERC approved rate of return
on common equity, a return on other capital (net of temporary cash investments)
and recovery of costs including operation and maintenance, fuel and taxes.

Net Income decreased $262 thousand for the second quarter of 2004 compared with
the second quarter of 2003 and decreased $231 thousand for the six months ended
June 30, 2004 compared with the six months ended June 30, 2003. The fluctuations
in Net Income are a result of terms in the unit power agreements which allow for
the return on total capital of the Rockport Plant calculated and adjusted
monthly.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income decreased $141 thousand for the second quarter of 2004 compared
with the second quarter of 2003. The largest variances related to:

 o  A $3 million decrease in Operating Revenue as a result of decreased
    recoverable expenses in accordance with the unit power agreements.
 o  A $4 million  decrease in Fuel for Electric  Generation  expense.  This
    decrease is primarily  due to a 16% decrease in MWH  generation  as a
    result of both planned  and forced outages.

Income Taxes
------------

The effective tax rates for the second quarter of 2004 and 2003 were (19.7)% and
(5.8)%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, amortization of investment tax credits and state income taxes. The
decrease in the effective tax rate is primarily due to lower pre-tax income in
2004, flow-through differences, and state income taxes.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income decreased $445 thousand for the six months ended June 30, 2004
compared with the six months ended June 30, 2003. The largest variances related
to:

 o  An $8 million decrease in Operating Revenue as a result of decreased
    recoverable expenses in accordance with the unit power agreements.
 o  A $4 million increase in Maintenance expense as a result of increased
    planned boiler inspections and forced repairs.
 o  A $13 million  decrease in Fuel for Electric  Generation  expense.  This
    decrease is primarily  due to a 23% decrease in MWH  generation as a result
    of both planned and forced outages.

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were (13.9)%
and (16.1)%, respectively. The difference in the effective income tax rate and
the federal statutory rate of 35% is due to flow-through of book versus tax
differences, amortization of investment tax credits and state income taxes. The
increase in the effective tax rate is primarily due to higher flow-through
differences and state income taxes offset by lower pre-tax income in 2004.

Off-balance Sheet Arrangements
------------------------------

In prior years, we entered into off-balance sheet arrangements. Our off-balance
sheet arrangement has not changed significantly from year-end 2003 and is
comprised of a sale and leaseback transaction entered into by AEGCo and I&M with
an unrelated unconsolidated trustee. Our current policy restricts the use of
off-balance sheet financing entities or structures, except for traditional
operating lease arrangements. For complete information on this off-balance
sheet arrangement see "Off-balance Sheet Arrangements" in "Management's
Narrative Financial Discussion and Analysis" section of our 2003 Annual Report.

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

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets and the impact of new accounting pronouncements.


<PAGE>
<TABLE>
<CAPTION>


                                                       AEP GENERATING COMPANY
                                                        STATEMENTS OF INCOME
                                      For the Three and Six Months Ended June 30, 2004 and 2003
                                                              (Unaudited)

                                                                 Three Months Ended                       Six Months Ended
                                                              ------------------------                ------------------------
                                                              2004                2003                2004                2003
                                                              ----                ----                ----                ----
                                                                                       (in thousands)

<C>                                                         <C>                 <C>                 <C>                 <C>
OPERATING REVENUES                                          $56,348             $59,568             $111,630            $119,996
                                                            --------            --------            ---------           ---------

             OPERATING EXPENSES
------------------------------------------
Fuel for Electric Generation                                 25,036              29,237               46,434              59,634
Rent - Rockport Plant Unit 2                                 17,071              17,071               34,142              34,142
Other Operation                                               2,665               2,442                5,155               4,991
Maintenance                                                   2,790               2,287                8,190               3,938
Depreciation and Amortization                                 5,772               5,665               11,506              11,286
Taxes Other Than Income Taxes                                   942                 604                1,886               1,395
Income Taxes                                                    699                 748                1,397               1,245
                                                            --------            --------            ---------           ---------
TOTAL                                                        54,975              58,054              108,710             116,631
                                                            --------            --------            ---------           ---------

OPERATING INCOME                                              1,373               1,514                2,920               3,365

Nonoperating Income                                               5                  19                   29                  21
Nonoperating Expenses                                            80                  25                  149                 242
Nonoperating Income Tax Credits                                 947                 845                1,804               1,739
Interest Charges                                                739                 585                1,271               1,319
                                                            --------            --------            ---------           ---------
NET INCOME                                                   $1,506              $1,768               $3,333              $3,564
                                                            ========            ========            =========           =========

</TABLE>
<TABLE>
<CAPTION>

                                                       STATEMENTS OF RETAINED EARNINGS
                                          For the Three and Six Months Ended June 30, 2004 and 2003
                                                                 (Unaudited)

                                                                   Three Months Ended                     Six Months Ended
                                                               ------------------------                ------------------------
                                                               2004                2003                2004                2003
                                                               ----                ----                ----                ----
                                                                                         (in thousands)

<C>                                                            <C>                <C>                  <C>               <C>
BALANCE AT BEGINNING OF PERIOD                                 $22,006            $18,788              $21,441           $18,163

Net Income                                                       1,506              1,768                3,333             3,564

Cash Dividends Declared                                          1,261              1,172                2,523             2,343
                                                               --------           --------             --------          --------

BALANCE AT END OF PERIOD                                       $22,251            $19,384              $22,251           $19,384
                                                               ========           ========             ========          ========

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

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



<PAGE>
<TABLE>
<CAPTION>


                                                           AEP GENERATING COMPANY
                                                               BALANCE SHEETS
                                                                   ASSETS
                                                      June 30, 2004 and December 31, 2003
                                                                (Unaudited)


                                                                                               2004                    2003
                                                                                               ----                    ----
                                                                                                       (in thousands)
<C>                                                                                          <C>                     <C>
            ELECTRIC UTILITY PLANT
----------------------------------------------
Production                                                                                   $667,819                $645,251
General                                                                                         4,039                   4,063
Construction Work in Progress                                                                   5,419                  24,741
                                                                                             ---------               ---------
TOTAL                                                                                         677,277                 674,055
Accumulated Depreciation                                                                      355,855                 351,062
                                                                                             ---------               ---------
TOTAL - NET                                                                                   321,422                 322,993
                                                                                             ---------               ---------

        OTHER PROPERTY AND INVESTMENTS
----------------------------------------------
Non-Utility  Property, Net                                                                        119                     119
                                                                                             ---------               ---------

               CURRENT ASSETS
----------------------------------------------
Accounts Receivable - Affiliated Companies                                                     23,996                  24,748
Fuel                                                                                           24,061                  20,139
Materials and Supplies                                                                          5,508                   5,419
Prepayments                                                                                        21                       -
                                                                                             ---------               ---------
TOTAL                                                                                          53,586                  50,306
                                                                                             ---------               ---------

       DEFERRED DEBITS AND OTHER ASSETS
----------------------------------------------
Regulatory Assets:
  Unamortized Loss on Reacquired Debt                                                           4,614                   4,733
  Asset Retirement Obligations                                                                  1,022                     928
Deferred Property Taxes                                                                         2,134                     502
Other Deferred Charges                                                                            436                     464
                                                                                             ---------               ---------
TOTAL                                                                                           8,206                   6,627
                                                                                             ---------               ---------


TOTAL ASSETS                                                                                 $383,333                $380,045
                                                                                             =========               =========


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


<PAGE>
<TABLE>
<CAPTION>


                                                       AEP GENERATING COMPANY
                                                           BALANCE SHEETS
                                                   CAPITALIZATION AND LIABILITIES
                                                June 30, 2004 and December 31, 2003
                                                             (Unaudited)

                                                                                                   2004                 2003
                                                                                                   ----                 ----
                                                                                                         (in thousands)
<C>                                                                                               <C>                 <C>
                    CAPITALIZATION
-----------------------------------------------------
Common Shareholder's Equity:
   Common Stock - Par Value $1,000 per share:
     Authorized and Outstanding - 1,000 Shares                                                      $1,000              $1,000
     Paid-in Capital                                                                                23,434              23,434
     Retained Earnings                                                                              22,251              21,441
                                                                                                  ---------           ---------
Total Common Shareholder's Equity                                                                   46,685              45,875
Long-term Debt                                                                                      44,815              44,811
                                                                                                  ---------           ---------
TOTAL                                                                                               91,500              90,686
                                                                                                  ---------           ---------

                  CURRENT LIABILITIES
-----------------------------------------------------
Advances from Affiliates                                                                            42,758              36,892
Accounts Payable:
   General                                                                                             897                 498
   Affiliated Companies                                                                             13,286              15,911
Taxes Accrued                                                                                       10,527               6,070
Interest Accrued                                                                                       911                 911
Obligations Under Capital Leases                                                                        69                  87
Rent Accrued - Rockport Plant Unit 2                                                                 4,963               4,963
Other                                                                                                   98                   -
                                                                                                  ---------           ---------
TOTAL                                                                                               73,509              65,332
                                                                                                  ---------           ---------

         DEFERRED CREDITS AND OTHER LIABILITIES
-----------------------------------------------------
Deferred Income Taxes                                                                               23,983              24,329
Regulatory Liabilities:
  Asset Removal Costs                                                                               27,863              27,822
  Deferred Investment Tax Credits                                                                   47,921              49,589
  SFAS 109 Regulatory Liability, Net                                                                14,531              15,505
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2                                        102,690             105,475
Obligations Under Capital Leases                                                                       166                 182
Asset Retirement Obligations                                                                         1,170               1,125
                                                                                                  ---------           ---------
TOTAL                                                                                              218,324             224,027
                                                                                                  ---------           ---------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                              $383,333            $380,045
                                                                                                  =========           =========



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


                                                     AEP GENERATING COMPANY
                                                    STATEMENTS OF CASH FLOWS
                                         For the Six Months Ended June 30, 2004 and 2003
                                                          (Unaudited)

                                                                                              2004             2003
                                                                                              ----             ----
                                                                                                  (in thousands)
<C>                                                                                          <C>              <C>
                     OPERATING ACTIVITIES
--------------------------------------------------------
Net Income                                                                                   $3,333           $3,564
Adjustments to Reconcile Net Income to Net Cash Flows From
 Operating Activities:
  Depreciation and Amortization                                                              11,506           11,286
  Deferred Income Taxes                                                                      (1,319)          (2,158)
  Deferred Investment Tax Credits                                                            (1,668)          (1,668)
  Deferred Property Taxes                                                                    (1,632)          (1,573)
  Amortization of Deferred Gain on Sale and Leaseback -
   Rockport Plant Unit 2                                                                     (2,785)          (2,785)
Changes in Certain Assets and Liabilities:
  Accounts Receivable                                                                           752           (4,174)
  Fuel, Materials and Supplies                                                               (4,011)           4,213
  Accounts Payable                                                                           (2,226)          (2,939)
  Taxes Accrued                                                                               4,457            3,806
  Change in Other Assets                                                                        (93)            (751)
  Change in Other Liabilities                                                                   154              884
                                                                                             -------          -------
Net Cash Flows From Operating Activities                                                      6,468            7,705
                                                                                             -------          -------

                     INVESTING ACTIVITIES
--------------------------------------------------------
Construction Expenditures                                                                    (9,811)          (4,012)
                                                                                             -------          -------
Net Cash Flows Used For Investing Activities                                                 (9,811)          (4,012)
                                                                                             -------          -------

                     FINANCING ACTIVITIES
--------------------------------------------------------
Change in Advances from Affiliates                                                            5,866           (1,350)
Dividends Paid                                                                               (2,523)          (2,343)
                                                                                             -------          -------
Net Cash Flows From (Used For) Financing Activities                                           3,343           (3,693)
                                                                                             -------          -------

Net Decrease in Cash and Cash Equivalents                                                         -                -
Cash and Cash Equivalents at Beginning of Period                                                  -                -
                                                                                             -------          -------
Cash and Cash Equivalents at End of Period                                                       $-               $-
                                                                                             =======          =======
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $1,138,000 and $1,186,000 and for income taxes was $570,000 and $2,448,000
in 2004 and 2003, respectively.

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

</TABLE>

<PAGE>



                             AEP GENERATING COMPANY
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to AEGCo's financial statements are combined with the notes to
financial statements for other subsidiary registrants. Listed below are the
notes that apply to AEGCo. The footnotes begin on page L-1.

                                                              Footnote
                                                              Reference
                                                              ---------

Significant Accounting Matters                                Note 1

New Accounting Pronouncements                                 Note 2

Commitments and Contingencies                                 Note 5

Guarantees                                                    Note 6

Business Segments                                             Note 9

Financing Activities                                          Note 10


<PAGE>










                    AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY


<PAGE>



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

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

Net Income decreased $99 million for 2004 year-to-date, and $64 million for the
second quarter. The three major factors driving the decline for both periods
are; the decreased revenues associated with establishing regulatory assets in
Texas, the provision for refunds of fuel charges, and the decrease in retail
delivery revenue due mainly to milder weather. These items accounted for a $99
million decrease year-to-date and a $70 million decrease for the quarter. The
cessation of depreciation on plants held for sale partially offset these
declines.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income decreased $73 million primarily due to:

 o  Decreased  revenues  associated with establishing  regulatory  assets in
    Texas of $52 million in 2003 (see "Texas Restructuring" in Note 4). These
    revenues did not continue after 2003.
 o  Increased provisions for rate refunds of $37 million due to fuel
    reconciliation issues (see "TCC Fuel Reconciliation" in Note 3).
 o  Decreased retail delivery revenues of $19 million driven primarily by a
    decrease in cooling degree-days of 23%.
 o  Decreased system sales, including those to REPs, of $88 million due mainly
    to lower KWH sales of 36% due to customer choice in Texas and a small
    decrease in the overall average price per KWH.
 o  Decreased  Reliability Must Run (RMR) revenues from ERCOT of $4 million,
    which includes both a fixed cost component decrease of $8 million and fuel
    recovery increase of $4 million.
 o  Decreased Qualified Scheduling Entity (QSE) fees of $3 million due mainly to
    one REP not using TCC as their QSE in 2004.
 o  Decreased margins of $16 million resulting from risk management activities.
 o  Increased Other Operation expenses of $10 million due mainly to $3 million
    increase of ERCOT-related transmission expense and affiliated ancillary
    services; $2 million higher customer related expenses; increased emission
    allowance expense and administrative and support expense of $3 million.
 o  Increased Taxes Other than Income Taxes of $3 million mainly due to
    increased property taxes.

The decrease in Operating Income was partially offset by:

 o  Net decreases in fuel and purchased electricity on a combined basis of $91
    million. KWH's purchased decreased 86% while the per unit cost increased 1%.
    Although the KWH generated increased 16%, generating costs increased 22%
    attributable mostly to higher prices for natural gas offset in part by both
    units of STP being on line in 2004 whereas in 2003 only one unit was
    operating.
 o  Increased revenues from ERCOT of $10 million for various services, including
    balancing energy.
 o  Increased transmission revenue of $1 million due mainly to affiliated OATT
    and ancillary services.
 o  Decreased Depreciation and Amortization expense of $25 million due mainly
    to the cessation of depreciation on Texas plants classified as "Held For
    Sale."

Other Impacts on Earnings
-------------------------

Nonoperating Income increased $4 million primarily as a result of increased
income of $8 million related to risk management activities offset in part by $4
million lower non-utility revenues associated with energy-related construction
projects for third parties.

Nonoperating Expense decreased $3 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties
offset in part by an increase in donations.

Interest charges decreased $3 million primarily due to the defeasance of $112
million of First Mortgage Bonds and the deferral of the interest cost as a cost
of the sale of generation assets as well as other financing activities.

Income Taxes
------------

The effective tax rates for the second quarter of 2004 and 2003 were 94.2% and
33.6%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The increase in the effective tax
rate is primarily due to pre-tax income becoming a loss in 2004 and lower state
income taxes.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income decreased $110 million primarily due to:

 o  Decreased  revenues  associated with establishing regulatory assets in
    Texas of $108 million in 2003 (see "Texas  Restructuring" in Note 4).
    These revenues did not continue after 2003.
 o  Increased provisions for rate refunds of $23 million due to fuel
    reconciliation issues (see "TCC Fuel Reconciliation" in Note 3).
 o  Decreased system sales, including  those to REPs, of $165 million due
    mainly to lower KWH sales of 33% due to customer choice in Texas and a
    small decrease in the overall average price per KWH.
 o  Decreased revenues from ERCOT of $4 million for various services, including
    balancing energy.
 o  Decreased retail delivery revenues of $22 million driven by a decrease of
    KWH of 3% due in large part to a decrease in cooling degree-days of 16%.
 o  Decreased  RMR revenues from ERCOT of $9 million, which includes both a
    fuel recovery decrease of $7 million and a fixed cost component decrease
    of $2 million.
 o  Decreased QSE fees of $8 million due mainly to one REP not using TCC as
    their QSE in 2004.
 o  Decreased margins from risk management activities of $15 million.
 o  Increased Other Operation expenses of $18 million due mainly to $8 million
    increase of ERCOT-related transmission expense and affiliated ancillary
    services; $2 million increase of production expense including emission
    allowances; $2 million increase in customer related expense; and an
    increase of $4 million of administrative and support expense.

The decrease in Operating Income was partially offset by:

 o  Net decreases in fuel and purchased electricity on a combined basis of
    $163 million. KWH purchased decreased 87% while the per unit cost
    increased 8%. The KWH generated increased 19% and per unit costs decreased
    8% attributable mostly to the fact that both units of STP were on line in
    2004.
 o  Increased transmission revenue of $11 million due mainly to affiliated OATT
    (including a $7.6 million 2004 true-up) and ancillary services.
 o  Decreased Depreciation and Amortization expense of $42 million due mainly
    to the cessation of depreciation on Texas plants classified as "Held For
    Sale."

Other Impacts on Earnings
-------------------------

Nonoperating Income increased $6 million primarily as a result of increased
income of $9 million related to risk management activities offset in part by $5
million lower non-utility revenues associated with energy-related construction
projects for third parties.

Nonoperating Expense decreased $3 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties
offset in part by an increase in donations.

Interest charges decreased $2 million primarily due to the defeasance of $112
million of First Mortgage Bonds and the deferral of the interest cost as a cost
of the sale of generation assets as well as other financing activities.

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were 18.2% and
34.4%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower pre-tax income in 2004 and lower state income
taxes.

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-

Cash Flow
---------

Cash flows for the six months ended June 30, 2004 and 2003 were as follows:

<TABLE>
<CAPTION>

                                                                                  2004                2003
                                                                                  ----                ----
                                                                                       (in thousands)
      <C>                                                                        <C>                <C>
      Cash and cash equivalents at beginning of period                              $760                $807
                                                                                 --------           ---------
      Cash flow from (used for):
        Operating activities                                                     118,414             186,201
        Investing activities                                                    (163,279)            (23,912)
        Financing activities                                                      49,915            (162,937)
                                                                                 --------           ---------
      Net increase (decrease) in cash and cash equivalents                         5,050                (648)
                                                                                 --------           ---------
      Cash and cash equivalents at end of period                                  $5,810                $159
                                                                                 ========           =========

</TABLE>

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

Cash Flows From Operating Activities in 2004 were $118 million primarily due to
Net Income, as explained above, Taxes Accrued, Accounts Payable and Changes in
Other Liabilities offset in part by Deferred Property Tax and Accounts
Receivable, Net.

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

Investing expenditures in 2004 were $163 million due primarily to $49 million in
construction expenditures focused on improved service reliability projects for
transmission and distribution systems, and $117 million in cash deposits for
future long-term debt retirement.

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

Cash used for financing activities in 2004 reduced Long-term Debt, paid
dividends and was offset by Advances to Affiliates.

Financing Activity
------------------

Long-term debt issuances, retirements and defeasance during the first six months
of 2004 were:

  Issuances
  ---------
             None

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

   First Mortgage Bonds           $ 6,195            6.625            2005
   Securitization Bonds            28,809            3.540            2005

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

   First Mortgage Bonds           $27,400            7.25             2004
   First Mortgage Bonds            65,763            6.625            2005
   First Mortgage Bonds            18,581            7.125            2008

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

We made progress on our planned divestiture of all our generation assets by (1)
announcing in January 2004 that we had signed an agreement to sell our 7.81%
share of the Oklaunion Power Station for approximately $43 million, subject to
closing adjustments, (2) announcing in February 2004 that we had signed an
agreement to sell our 25.2% share of the South Texas Project nuclear plant for
approximately $333 million, subject to closing adjustments, and (3) closing on
the sale of our remaining generation assets, including eight natural gas plants,
one coal-fired plant and one hydro plant for approximately $425 million, net of
closing adjustments. Subject to certain issues that have arisen relating to
co-owners' rights of first refusal, we expect the sales of our share of
Oklaunion and South Texas Project to close before the end of 2004. There could,
however, be potential delays in receiving appropriate regulatory approvals and
clearances which may delay the closing. The sale of our remaining generation
assets was completed in July 2004. We will file with the Public Utility
Commission of Texas to recover net stranded costs associated with the sales
pursuant to Texas restructuring legislation.

Nuclear Decommissioning
-----------------------

As discussed in the 2003 Annual Report, decommissioning costs are accrued over
the service life of STP. The licenses to operate the two nuclear units at STP
expire in 2027 and 2028. TCC had estimated its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of approximately $8 million per year.

In May 2004, an updated decommissioning study was completed for STP. The study
estimates TCC's share of the decommissioning costs of STP to be $344 million in
nondiscounted 2004 dollars. TCC is in the process of selling its ownership
interest in STP to a non-affiliate, and upon completion of the sale it is
anticipated that TCC will no longer be obligated for nuclear decommissioning
liabilities associated with STP.

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion on factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report 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
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.

MTM Risk Management Contract Net Liabilities
--------------------------------------------

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

<TABLE>
<CAPTION>

                                     MTM Risk Management Contract Net Liabilities
                                           Six Months Ended June 30, 2004
                                                    (in thousands)

<C>                                                                                                           <C>
Total MTM Risk Management Contract Net Assets at December 31, 2003                                             $11,942
(Gain) Loss from Contracts Realized/Settled During the Period (a)                                               (2,867)
Fair Value of New Contracts When Entered Into During the Period (b)                                                  -
Net Option Premiums Paid/(Received) (c)                                                                             45
Change in Fair Value Due to Valuation Methodology Changes (d)                                                      110
Changes in Fair Value of Risk Management Contracts (e)                                                          (1,881)
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)                          -
                                                                                                              ---------
Total MTM Risk Management Contract Net Assets                                                                    7,349
Net Cash Flow Hedge Contracts (g)                                                                              (15,162)
                                                                                                              ---------
Total MTM Risk Management Contract Net Liabilities at June 30, 2004                                            $(7,813)
                                                                                                              =========
</TABLE>

(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
    includes realized risk management contracts and related derivatives
    that settled during 2004 that were entered into prior to 2004.
(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 2004. 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 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
    represents the impact of AEP changes in methodology in regards to
    credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
    fair value change in the risk management portfolio due to market
    fluctuations during the current period. Market fluctuations are
    attributable to various factors such as supply/demand, weather,
    etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
    Regulated Jurisdictions" relates to the net gains (losses) of those
    contracts that are not reflected in the Consolidated Statements of
    Operations. These net gains (losses) are recorded as regulatory
    liabilities/assets for those subsidiaries that operate in regulated
    jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
    Accumulated Other Comprehensive Income (Loss).

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

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

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

<TABLE>
<CAPTION>

                                                  Maturity and Source of Fair Value of MTM
                                                    Risk Management Contract Net Assets
                                                 Fair Value of Contracts as of June 30, 2004

                                              Remainder                                                      After
                                                 2004           2005        2006        2007       2008      2008      Total (c)
                                              ---------         ----        ----        ----       ----      -----     ---------
<C>                                             <C>           <C>           <C>         <C>        <C>        <C>       <C>
Prices Actively Quoted - Exchange
 Traded Contracts                               $(277)           $27        $(1)         $88         $-        $-       $(163)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                 (913)           580        115            -          -         -        (218)
Prices Based on Models and Other
 Valuation Methods (b)                          6,481            451        (33)          87        187       557       7,730
                                               -------        -------       ----        -----      -----     -----     -------

Total                                          $5,291         $1,058        $81         $175       $187      $557      $7,349
                                               =======        =======       ====        =====      =====     =====     =======
</TABLE>

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

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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.

       Total Accumulated Other Comprehensive Income (Loss) Activity
                      Six Months Ended June 30, 2004

                                                           Power
                                                           -----
                                                       (in thousands)
     Beginning Balance December 31, 2003                   $(1,828)
     Changes in Fair Value (a)                              (8,941)
     Reclassifications from AOCI to Net
      Income (b)                                              (473)
                                                          ---------
     Ending Balance June 30, 2004                         $(11,242)
                                                          =========

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

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $11,145 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:

        Six Months Ended                          Twelve Months Ended
         June 30, 2004                             December 31, 2003
        ----------------                          -------------------
         (in thousands)                             (in thousands)

End     High     Average    Low              End     High   Average    Low
---     ----     -------    ---              ---     ----   -------    ---
$71     $161       $80      $40             $189     $733     $307     $73

VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $189 million and $206 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.


<PAGE>
<TABLE>
<CAPTION>


                                                 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                  CONSOLIDATED STATEMENTS OF OPERATIONS
                                       For the Three and Six Months Ended June 30, 2004 and 2003
                                                              (Unaudited)

                                                                           Three Months Ended                 Six Months Ended
                                                                         ----------------------             ---------------------
                                                                         2004              2003             2004             2003
                                                                         ----              ----             ----             ----
                                                                                               (in thousands)
<C>                                                                     <C>              <C>              <C>              <C>
              OPERATING REVENUES
----------------------------------------------------
Electric Generation, Transmission and Distribution                      $256,964         $439,049         $525,822         $821,179
Sales to AEP Affiliates                                                   12,896           43,397           31,026           89,625
                                                                        ---------        ---------        ---------        ---------
TOTAL                                                                    269,860          482,446          556,848          910,804
                                                                        ---------        ---------        ---------        ---------

              OPERATING EXPENSES
----------------------------------------------------
Fuel for Electric Generation                                              20,806           21,430           43,912           48,769
Fuel from Affiliates for Electric Generation                              59,977           44,911          100,176           83,200
Purchased Electricity for Resale                                          16,468          116,654           26,554          188,776
Purchased Electricity from AEP Affiliates                                  1,938            7,210            6,011           18,772
Other Operation                                                           77,977           68,283          153,418          135,678
Maintenance                                                               23,709           21,811           39,113           37,910
Depreciation and Amortization                                             28,879           53,867           57,976           99,947
Taxes Other Than Income Taxes                                             23,157           19,783           45,214           42,762
Income Taxes (Credits)                                                    (6,388)          31,894            5,618           66,377
                                                                        ---------        ---------        ---------        ---------
TOTAL                                                                    246,523          385,843          477,992          722,191
                                                                        ---------        ---------        ---------        ---------

OPERATING INCOME                                                          23,337           96,603           78,856          188,613

Nonoperating Income                                                       12,061            7,901           24,163           18,063
Nonoperating Expenses                                                      2,648            5,637            7,756           10,832
Nonoperating Income Tax Expense                                              880              240              860              798
Interest Charges                                                          32,211           35,040           65,340           67,022
                                                                        ---------        ---------        ---------        ---------

Income (Loss) Before Cumulative Effect of Accounting Change                 (341)          63,587           29,063          128,024
Cumulative Effect of Accounting Change (Net of Tax)                            -                -                -              122
                                                                        ---------        ---------        ---------        ---------

NET INCOME (LOSS)                                                           (341)          63,587           29,063          128,146

Preferred Stock Dividend Requirements                                         61               61              121              121
                                                                        ---------        ---------        ---------        ---------

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                                 $(402)         $63,526          $28,942         $128,025
                                                                        =========        =========        =========        =========

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

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>


                                                    AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                           CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                        EQUITY AND COMPREHENSIVE INCOME
                                                For the Six Months Ended June 30, 2004 and 2003
                                                                (in thousands)
                                                                  (Unaudited)


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

<C>                                                  <C>           <C>             <C>                   <C>           <C>
DECEMBER 31, 2002                                    $55,292       $132,606          $986,396            $(73,160)     $1,101,134

Common Stock Dividends                                                                (60,401)                            (60,401)
Preferred Stock Dividends                                                                (121)                               (121)
                                                                                                                       -----------
TOTAL                                                                                                                   1,040,612
                                                                                                                       -----------

          COMPREHENSIVE INCOME
----------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Cash Flow Hedges                                                                                          (747)           (747)
NET INCOME                                                                            128,146                             128,146
                                                                                                                       -----------
TOTAL COMPREHENSIVE INCOME                                                                                                127,399
                                                     --------      ---------       -----------           ---------     -----------
JUNE 30, 2003                                        $55,292       $132,606        $1,054,020            $(73,907)     $1,168,011
                                                     ========      =========       ===========           =========     ===========


DECEMBER 31, 2003                                    $55,292       $132,606        $1,083,023            $(61,872)     $1,209,049

Common Stock Dividends                                                                (48,000)                            (48,000)
Preferred Stock Dividends                                                                (121)                               (121)
                                                                                                                       -----------
TOTAL                                                                                                                   1,160,928
                                                                                                                       -----------

          COMPREHENSIVE INCOME
----------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Cash Flow Hedges                                                                                        (9,414)         (9,414)
   Minimum Pension Liability                                                                               (2,466)         (2,466)
NET INCOME                                                                             29,063                              29,063
                                                                                                                       -----------
TOTAL COMPREHENSIVE INCOME                                                                                                 17,183
                                                     --------      ---------       -----------           ---------     -----------
JUNE 30, 2004                                        $55,292       $132,606        $1,063,965            $(73,752)     $1,178,111
                                                     ========      =========       ===========           =========     ===========

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


                                               AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                     CONSOLIDATED BALANCE SHEETS
                                                              ASSETS
                                                June 30, 2004 and December 31, 2003
                                                            (Unaudited)

                                                                                                      2004                  2003
                                                                                                      ----                  ----
                                                                                                             (in thousands)
<C>                                                                                               <C>                    <C>
                 ELECTRIC UTILITY PLANT
------------------------------------------------------
Production                                                                                                $-                     $-
Transmission                                                                                         776,784                767,970
Distribution                                                                                       1,402,159              1,376,761
General                                                                                              225,610                221,354
Construction Work in Progress                                                                         51,586                 58,953
                                                                                                  -----------            -----------
TOTAL                                                                                              2,456,139              2,425,038
Accumulated Depreciation and Amortization                                                            713,376                695,359
                                                                                                  -----------            -----------
TOTAL - NET                                                                                        1,742,763              1,729,679
                                                                                                  -----------            -----------

             OTHER PROPERTY AND INVESTMENTS
------------------------------------------------------
Non-Utility Property, Net                                                                              1,340                  1,302
Bond Defeasance Funds                                                                                 21,773                      -
Other Investments                                                                                          -                  4,639
                                                                                                  -----------            -----------
TOTAL                                                                                                 23,113                  5,941
                                                                                                  -----------            -----------

                    CURRENT ASSETS
------------------------------------------------------
Cash and Cash Equivalents                                                                              5,810                    760
Other Cash Deposits                                                                                  158,729                 65,122
Advances to Affiliates                                                                                     -                 60,699
Accounts Receivable:
   Customers                                                                                         189,128                146,630
   Affiliated Companies                                                                               64,321                 78,484
   Accrued Unbilled Revenues                                                                          21,920                 23,077
   Allowance for Uncollectible Accounts                                                               (2,306)                (1,710)
Materials and Supplies                                                                                13,705                 11,708
Risk Management Assets                                                                                13,636                 22,051
Margin Deposits                                                                                          245                  3,230
Prepayments and Other Current Assets                                                                  10,119                  6,770
                                                                                                  -----------            -----------
TOTAL                                                                                                475,307                416,821
                                                                                                  -----------            -----------

             DEFERRED DEBITS AND OTHER ASSETS
------------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Asset, Net                                                                       3,100                  3,249
  Wholesale Capacity Auction True-up                                                                 480,000                480,000
  Unamortized Loss on Reacquired Debt                                                                  8,606                  9,086
  Designated for Securitization                                                                    1,262,049              1,253,289
  Deferred Debt - Restructuring                                                                       11,937                 12,015
  Other                                                                                              123,090                133,913
Securitized Transition Assets                                                                        669,942                689,399
Long-term Risk Management Assets                                                                       2,797                  7,627
Deferred Charges                                                                                      71,248                 55,554
                                                                                                  -----------            -----------
TOTAL                                                                                              2,632,769              2,644,132
                                                                                                  -----------            -----------

Assets Held for Sale - Texas Generation Plants                                                     1,037,138              1,028,134
                                                                                                  -----------            -----------

TOTAL ASSETS                                                                                      $5,911,090             $5,824,707
                                                                                                  ===========            ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                              AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                    CONSOLIDATED BALANCE SHEETS
                                                   CAPITALIZATION AND LIABILITIES
                                                June 30, 2004 and December 31, 2003
                                                           (Unaudited)
                                                                                                       2004                2003
                                                                                                       ----                ----
                                                                                                            (in thousands)

<C>                                                                                                <C>                 <C>
                       CAPITALIZATION
---------------------------------------------------------------
Common Shareholder's Equity:
  Common Stock - $25 Par Value:
    Authorized - 12,000,000 Shares
    Outstanding - 2,211,678 Shares                                                                    $55,292             $55,292
    Paid-in Capital                                                                                   132,606             132,606
    Retained Earnings                                                                               1,063,965           1,083,023
    Accumulated Other Comprehensive Income (Loss)                                                     (73,752)            (61,872)
                                                                                                   -----------         -----------
Total Common Shareholder's Equity                                                                   1,178,111           1,209,049
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                          5,940               5,940
                                                                                                   -----------         -----------
Total Shareholder's Equity                                                                          1,184,051           1,214,989
Long-term Debt                                                                                      1,627,705           2,053,974
                                                                                                   -----------         -----------
TOTAL                                                                                               2,811,756           3,268,963
                                                                                                   -----------         -----------

                     CURRENT LIABILITIES
---------------------------------------------------------------
Long-term Debt Due Within One Year                                                                    629,118             237,651
Advances From Affiliates                                                                               72,341                   -
Accounts Payable:
  General                                                                                              97,642              90,004
  Affiliated Companies                                                                                 84,952              74,209
Customer Deposits                                                                                       5,878               1,517
Taxes Accrued                                                                                          98,396              67,018
Interest Accrued                                                                                       42,440              43,196
Risk Management Liabilities                                                                            22,657              17,888
Obligation Under Capital Leases                                                                           420                 407
Other                                                                                                  20,063              23,248
                                                                                                   -----------         -----------
TOTAL                                                                                               1,073,907             555,138
                                                                                                   -----------         -----------

              DEFERRED CREDITS AND OTHER LIABILITIES
---------------------------------------------------------------
Deferred Income Taxes                                                                               1,233,508           1,244,912
Long-term Risk Management Liabilities                                                                   1,589               2,660
Regulatory Liabilities:
  Asset Removal Costs                                                                                  99,900              95,415
  Deferred Investment Tax Credits                                                                     109,875             112,479
  Deferred Fuel Costs                                                                                  69,026              69,026
  Retail Clawback                                                                                      29,824              45,527
  Other                                                                                                44,812              56,984
Obligation Under Capital Leases                                                                           563                 636
Deferred Credits and Other                                                                            200,028             144,833
                                                                                                   -----------         -----------
TOTAL                                                                                               1,789,125           1,772,472
                                                                                                   -----------         -----------

Liabilities Held for Sale - Texas Generation Plants                                                   236,302             228,134
                                                                                                   -----------         -----------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                               $5,911,090          $5,824,707
                                                                                                   ===========         ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>




                                                  AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                              For the Six Months Ended June 30, 2004 and 2003
                                                                (Unaudited)

                                                                                                 2004                2003
                                                                                                 ----                ----
                                                                                                       (in thousands)
<C>                                                                                            <C>                  <C>
                 OPERATING ACTIVITIES
-----------------------------------------------------------
Net Income                                                                                      $29,063             $128,146
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Cumulative Effect of Accounting Change                                                             -                 (122)
   Depreciation and Amortization                                                                 57,976               99,947
   Deferred Income Taxes                                                                        (11,682)              13,369
   Deferred Investment Tax Credits                                                               (2,603)              (2,603)
   Deferred Property Taxes                                                                      (22,440)             (20,100)
   Mark-to-Market of Risk Management Contracts                                                    4,593                1,955
   Wholesale Capacity Auction True-up                                                                 -             (108,400)
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                                     (26,582)             (87,691)
   Fuel, Materials and Supplies                                                                  (3,735)              16,456
   Accounts Payable                                                                              18,381               83,970
   Taxes Accrued                                                                                 31,378               48,277
   Interest Accrued                                                                                (756)              (7,610)
Change in Other Assets                                                                            3,094                9,644
Change in Other Liabilities                                                                      41,727               10,963
                                                                                               ---------            ---------
Net Cash Flows From Operating Activities                                                        118,414              186,201
                                                                                               ---------            ---------

                INVESTING ACTIVITIES
-----------------------------------------------------------
Construction Expenditures                                                                       (49,311)             (56,013)
Change in Other Cash Deposits, Net                                                              (93,607)              32,101
Change in Bond Defeasance Funds and Other                                                       (20,361)                   -
                                                                                               ---------            ---------
Net Cash Flows Used For Investing Activities                                                   (163,279)             (23,912)
                                                                                               ---------            ---------
                 FINANCING ACTIVITIES
-----------------------------------------------------------
Change in Short-term Debt - Affiliates                                                                -             (650,000)
Issuance of Long-term Debt                                                                            -              792,027
Retirement of Long-term Debt                                                                    (35,004)             (66,230)
Change in Advances to Affiliates                                                                133,040             (178,212)
Dividends Paid on Common Stock                                                                  (48,000)             (60,401)
Dividends Paid on Cumulative Preferred Stock                                                       (121)                (121)
                                                                                               ---------            ---------
Net Cash Flows From (Used For) Financing Activities                                              49,915             (162,937)
                                                                                               ---------            ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                              5,050                 (648)
Cash and Cash Equivalents at Beginning of Period                                                    760                  807
                                                                                               ---------            ---------
Cash and Cash Equivalents at End of Period                                                       $5,810                 $159
                                                                                               =========            =========


SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $61,529,000 and $72,918,000 and for income taxes was $(7,067,000)
and $7,803,000 in 2004 and 2003, respectively.

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



                    AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to TCC's consolidated financial statements are combined with the notes
to financial statements for other subsidiary registrants. Listed below are the
notes that apply to TCC. The footnotes begin on page L-1.

                                                               Footnote
                                                               Reference
                                                               ---------

Significant Accounting Matters                                 Note 1

New Accounting Pronouncements                                  Note 2

Rate Matters                                                   Note 3

Customer Choice and Industry Restructuring                     Note 4

Commitments and Contingencies                                  Note 5

Guarantees                                                     Note 6

Dispositions and Assets Held for Sale                          Note 7

Benefit Plans                                                  Note 8

Business Segments                                              Note 9

Financing Activities                                           Note 10




<PAGE>








                             AEP TEXAS NORTH COMPANY



<PAGE>


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

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

Net Income decreased $7 million for 2004 year-to-date, and $10 million for the
second quarter. The year-to-date decrease was driven by lower margins from risk
management activities and lower retail delivery revenues in Texas. These same
items drive the quarterly decline along with a provision for rate refunds from
fuel reconciliation proceedings.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income decreased by $12 million primarily due to:

 o  Increased provision for rate refunds of $13 million due to fuel
    reconciliation issues (see "TNC Fuel Reconciliation" in Note 3).
 o  Decreased margins from risk management activities of $8 million.
 o  Decreased retail delivery revenues of $3 million due partly to a 13% decline
    in cooling degree-days.
 o  Decreased system sales, including those to REPs, of $16 million due mainly
    to both lower KWH sales of 17% and a small decrease in the overall average
    price per KWH sold.
 o  Decrease of Reliability Must Run (RMR) revenues from ERCOT of $1 million
    which include both fuel recovery and a fixed cost component.
 o  Increased Taxes Other than Income Taxes of $2 million resulting mainly from
    higher accrued property taxes.

The decrease in Operating Income was partially offset by:

 o  Decreased fuel and purchased power on a combined basis of $15 million. KWH
    generation increased 16%, while the generation cost per KWH increased 4%
    due primarily to increases in the price of natural gas. KWH purchased
    declined 9%, and the average cost per KWH purchased decreased 37%.
 o  Revenues from ERCOT increased $4 million for various services, including
    balancing energy, due mainly to prior years adjustments made by ERCOT
    recorded in 2003.
 o  Increased wholesale revenues of $2 million due to higher fuel revenue, as
    the pricing is linked to average fuel cost.
 o  Increased Transmission revenue of $1 million, due mainly to affiliated
    ancillary services.
 o  Decreased Other Operation expenses of $3 million, primarily due to proceeds
    of $1 million for the sale of emission allowances; decreased production
    expense of approximately $2 million due to the elimination of the RMR
    status for the San Angelo Power Station - Unit 1; and decreased employee
    related expenses.

Other Impacts on Earnings
-------------------------

Nonoperating Income decreased $2 million as a result of a $5 million decrease in
non-utility revenues associated with energy-related construction projects for
third parties, offset in part by an increase of $3 million related to risk
management activities.

Nonoperating Expense decreased $5 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties.

Income Taxes
------------

The effective tax rates for the second quarter of 2004 and 2003 were 32.6% and
35.4% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower pre-tax income in 2004 and lower state income
taxes.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income decreased by $5 million primarily due to:

 o  Decreased  system  sales, including those to REPs, of $44 million due mainly
    to both lower KWH sales of 24% due to  customer  choice in Texas and a small
    decrease in the overall average price per KWH.
 o  Decreased retail delivery revenues of $3 million due partly to an 11%
    decline in cooling degree-days.
 o  Increased provision for rate refunds of $1 million due to fuel
    reconciliation issues in 2003 (see "TNC Fuel Reconciliation" in Note 3).
 o  Decreased margins from risk management activities of $9 million.
 o  Decreased revenues from ERCOT of $1 million for various services, including
    balancing energy, due mainly to prior year adjustments made by ERCOT and
    recorded in 2003.
 o  Increased Taxes Other than Income Taxes of $1 million resulting mainly from
    higher accrued property taxes.

The decrease in Operating Income was partially offset by:

 o  Decreased fuel and purchased power on a combined basis of $37 million. KWH
    purchased declined 31%, and the average cost per KWH purchased decreased
    34%. KWH generation increased 6%, while the generation cost per KWH
    increased 8% due primarily to increases in the price of natural gas.
 o  Increased Transmission revenue of $8 million, due mainly to prior year
    adjustments recorded in 2003 for affiliated OATT and ancillary services
    resulting from revised data received from ERCOT for the years 2001-2003.
 o  Increase of RMR revenues from ERCOT of $4 million, which include both a fuel
    recovery increase of $6 million and a fixed cost decrease of $2 million.
 o  Increased wholesale revenues of $1 million due to higher fuel revenue which
    is linked to average fuel cost pricing.
 o  Decreased Other Operation expenses of $3 million, primarily due to proceeds
    of $1 million for the sale of emission allowances, decreased production
    expense of approximately $2 million due to the elimination of the RMR status
    for the San Angelo Power Station - Unit 1, as well as decreased
    employee-related expenses.

Other Impacts on Earnings
-------------------------

Nonoperating Income decreased $2 million primarily as a result of a $5 million
decrease in non-utility revenue associated with energy-related construction
projects for third parties, offset in part by an increase of $3 million related
to risk management activities.

Nonoperating Expense decreased $6 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties.

The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 in 2003.

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were 33.7% and
37.1% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower pre-tax income in 2004 and lower state income
taxes.

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-

Financing Activity
------------------

Long-term debt issuances and retirements during the first six months of 2004
were:

  Issuances
  ---------

   None.

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

   First Mortgage Bonds          $24,036           6.125             2004

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

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report 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
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effects.

MTM Risk Management Contract Net Liabilities
--------------------------------------------

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

<TABLE>
<CAPTION>

                           MTM Risk Management Contract Net Liabilities
                                   Six Months Ended June 30, 2004
                                          (in thousands)

<C>                                                                                                 <C>
Total MTM Risk Management Contract Net Assets at December 31, 2003                                   $4,620
(Gain) Loss from Contracts Realized/Settled During the Period (a)                                      (982)
Fair Value of New Contracts When Entered Into During the Period (b)                                      -
Net Option Premiums Paid/(Received) (c)                                                                  20
Change in Fair Value Due to Valuation Methodology Changes (d)                                            45
Changes in Fair Value of Risk Management Contracts (e)                                               (1,038)
Changes in Fair Value of Risk Management Contracts Allocated to
 Regulated Jurisdictions (f)                                                                              -
                                                                                                    --------
Total MTM Risk Management Contract Net Assets                                                         2,665
Net Cash Flow Hedge Contracts (g)                                                                    (5,083)
                                                                                                    --------
Total MTM Risk Management Contract Net Liabilities at June 30, 2004                                 $(2,418)
                                                                                                    ========

</TABLE>

(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
    includes realized risk management contracts and related derivatives
    that settled during 2004 that were entered into prior to 2004.
(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 2004. 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 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
    represents the impact of AEP changing methodology in regards to
    credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
    fair value change in the risk management portfolio due to market
    fluctuations during the current period. Market fluctuations are
    attributable to various factors such as supply/demand, weather,
    etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
    Regulated Jurisdictions" relates to the net gains (losses) of those
    contracts that are not reflected in the Statements of Income. These
    net gains (losses) are recorded as regulatory liabilities/assets
    for those subsidiaries that operate in regulated jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
    Accumulated Other Comprehensive Income (Loss).



<PAGE>


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

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

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

<TABLE>
<CAPTION>

                                               Maturity and Source of Fair Value of MTM
                                                 Risk Management Contract Net Assets
                                              Fair Value of Contracts as of June 30, 2004

                                                Remainder                                                     After
                                                  2004          2005          2006       2007      2008       2008     Total (c)
                                                ---------       ----          ----       ----      ----       -----    ---------

<C>                                              <C>            <C>           <C>         <C>      <C>        <C>      <C>
Prices Actually Quoted - Exchange Traded
 Contracts                                        $(111)         $11           $-         $35       $-          $-       $(65)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                   (231)         233           46           -        -           -         48
Prices Based on Models and Other
 Valuation Methods (b)                            2,180          181          (13)         35       75         224      2,682
                                                 -------        -----         ----        ----     ----       -----    -------

Total                                            $1,838         $425          $33         $70      $75        $224     $2,665
                                                 =======        =====         ====        ====     ====       =====    =======
</TABLE>

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


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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.

          Total Accumulated Other Comprehensive Income (Loss) Activity
                         Six Months Ended June 30, 2004

                                                               Power
                                                               -----
                                                          (in thousands)

     Beginning Balance December 31, 2003                       $(601)
     Changes in Fair Value (a)                                (3,001)
     Reclassifications from AOCI to Net
      Income (b)                                                (163)
                                                             --------
     Ending Balance June 30, 2004                            $(3,765)
                                                             ========

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

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $3,727 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:

        Six Months Ended                          Twelve Months Ended
         June 30, 2004                             December 31, 2003
        ----------------                          -------------------
         (in thousands)                             (in thousands)

End     High     Average    Low              End     High   Average    Low
---     ----     -------    ---              ---     ----   -------    ---
$29     $65       $32       $16              $76     $294    $123      $29

VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $31 million and $33 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore, a near term change in interest rates should
not negatively affect our results of operation or financial position.


<PAGE>
<TABLE>
<CAPTION>


                                                           AEP TEXAS NORTH COMPANY
                                                            STATEMENTS OF INCOME
                                         For the Three and Six Months Ended June 30, 2004 and 2003
                                                                (Unaudited)

                                                                          Three Months Ended                  Six Months Ended
                                                                         ---------------------             ---------------------
                                                                         2004             2003             2004             2003
                                                                         ----             ----             ----             ----
                                                                                             (in thousands)
<C>                                                                   <C>              <C>              <C>                <C>
                   OPERATING REVENUES
-----------------------------------------------------------
Electric Generation, Transmission and Distribution                    $88,968         $120,568         $177,680           $216,629
Sales to AEP Affiliates                                                12,027           16,238           26,745             36,439
                                                                      --------         --------         --------           --------
TOTAL                                                                 100,995          136,806          204,425            253,068
                                                                      --------         --------         --------           --------


                   OPERATING EXPENSES
-----------------------------------------------------------
Fuel for Electric Generation                                           10,661            8,278           18,161             19,739
Fuel from Affiliates for Electric Generation                           12,542           10,917           23,766             17,002
Purchased Electricity for Resale                                       23,282           26,723           41,305             51,501
Purchased Electricity from AEP Affiliates                                 544           16,449            4,076             35,794
Other Operation                                                        19,556           22,365           39,937             42,984
Maintenance                                                             5,950            6,012           10,633             10,153
Depreciation and Amortization                                           9,854            9,723           19,546             19,255
Taxes Other Than Income Taxes                                           5,293            3,432           10,397              9,465
Income Taxes                                                            2,541            9,664            8,482             14,067
                                                                      --------         --------         --------           --------
TOTAL                                                                  90,223          113,563          176,303            219,960
                                                                      --------         --------         --------           --------

OPERATING INCOME                                                       10,772           23,243           28,122             33,108

Nonoperating Income                                                    15,632           17,834           29,388             31,305
Nonoperating Expenses                                                  11,962           17,114           22,898             28,681
Nonoperating Income Tax Expense                                         1,209              142            2,103                481
Interest Charges                                                        5,482            5,899           11,662             10,564
                                                                      --------         --------         --------           --------

Income Before Cumulative Effect of Accounting Changes                   7,751           17,922           20,847             24,687

Cumulative Effect of Accounting Changes (Net of Tax)                        -                -                -              3,071
                                                                      --------         --------         --------           --------

NET INCOME                                                              7,751           17,922           20,847             27,758

Preferred Stock Dividend Requirements                                      26               26               52                 52
                                                                      --------         --------         --------           --------

EARNINGS APPLICABLE TO COMMON STOCK                                    $7,725          $17,896          $20,795            $27,706
                                                                      ========         ========         ========           ========

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

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



                                                      AEP TEXAS NORTH COMPANY
                                            STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                  EQUITY AND COMPREHENSIVE INCOME
                                           For the Six Months Ended June 30, 2004 and 2003
                                                          (in thousands)
                                                           (Unaudited)

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

<C>                                                  <C>               <C>            <C>                 <C>             <C>
DECEMBER 31, 2002                                    $137,214          $2,351          $71,942            $(30,763)       $180,744

Common Stock Dividends                                                                  (4,970)                             (4,970)
Preferred Stock Dividends                                                                  (52)                                (52)
                                                                                                                          ---------
TOTAL                                                                                                                      175,722
                                                                                                                          ---------

           COMPREHENSIVE INCOME
------------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Cash Flow Hedges                                                                                           (309)           (309)
   Minimum Pension Liability                                                                                    (7)             (7)
NET INCOME                                                                              27,758                              27,758
                                                                                                                          ---------
TOTAL COMPREHENSIVE INCOME                                                                                                  27,442
                                                     ---------         -------        ---------           ---------       ---------
JUNE 30, 2003                                        $137,214          $2,351          $94,678            $(31,079)       $203,164
                                                     =========         =======        =========           =========       =========


DECEMBER 31, 2003                                    $137,214          $2,351         $125,428            $(26,718)       $238,275

Common Stock Dividends                                                                  (2,000)                             (2,000)
Preferred Stock Dividends                                                                  (52)                                (52)
                                                                                                                          ---------
TOTAL                                                                                                                      236,223
                                                                                                                          ---------

           COMPREHENSIVE INCOME
------------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Cash Flow Hedges                                                                                         (3,164)         (3,164)
NET INCOME                                                                              20,847                              20,847
                                                                                                                          ---------
TOTAL COMPREHENSIVE INCOME                                                                                                  17,683
                                                     ---------         -------        ---------           ---------       ---------
JUNE 30, 2004                                        $137,214          $2,351         $144,223            $(29,882)       $253,906
                                                     =========         =======        =========           =========       =========

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



                                                         AEP TEXAS NORTH COMPANY
                                                              BALANCE SHEETS
                                                                  ASSETS
                                                  June 30, 2004 and December 31, 2003
                                                               (Unaudited)

                                                                                                 2004                    2003
                                                                                                 ----                    ----
                                                                                                        (in thousands)
<C>                                                                                          <C>                     <C>
                ELECTRIC UTILITY PLANT
----------------------------------------------------
Production                                                                                     $361,620                $360,463
Transmission                                                                                    275,081                 268,695
Distribution                                                                                    465,965                 456,278
General                                                                                         120,557                 117,792
Construction Work in Progress                                                                    25,582                  30,199
                                                                                             -----------             -----------
TOTAL                                                                                         1,248,805               1,233,427
Accumulated Depreciation and Amortization                                                       469,153                 460,513
                                                                                             -----------             -----------
TOTAL - NET                                                                                     779,652                 772,914
                                                                                             -----------             -----------

            OTHER PROPERTY AND INVESTMENTS
----------------------------------------------------
Non-Utility Property, Net                                                                         1,181                   1,286
                                                                                             -----------             -----------
TOTAL                                                                                             1,181                   1,286
                                                                                             -----------             -----------

                   CURRENT ASSETS
----------------------------------------------------
Cash and Cash Equivalents                                                                         1,387                       -
Other Cash Deposits                                                                               2,297                   2,863
Advances to Affiliates                                                                           47,984                  41,593
Accounts Receivable:
  Customers                                                                                      70,674                  56,670
  Affiliated Companies                                                                           18,759                  28,910
  Accrued Unbilled Revenues                                                                       3,537                   4,871
  Miscellaneous                                                                                     521                   3,411
  Allowance for Uncollectible Accounts                                                              (85)                   (175)
Fuel Inventory                                                                                    8,852                  10,925
Materials and Supplies                                                                            8,619                   8,866
Risk Management Assets                                                                            4,877                  10,340
Margin Deposits                                                                                      87                   1,285
Prepayments and Other                                                                             1,477                   1,834
                                                                                             -----------             -----------
TOTAL                                                                                           168,986                 171,393
                                                                                             -----------             -----------

           DEFERRED DEBITS AND OTHER ASSETS
----------------------------------------------------
Regulatory Assets:
  Deferred Fuel Costs                                                                            26,680                  26,680
  Deferred Debt - Restructuring                                                                   6,336                   6,579
  Unamortized Loss on Reacquired Debt                                                             2,967                   3,929
  Other                                                                                           2,949                   3,332
Long-term Risk Management Assets                                                                  1,124                   3,106
Deferred Charges                                                                                 31,671                  20,290
                                                                                             -----------             -----------
TOTAL                                                                                            71,727                  63,916
                                                                                             -----------             -----------

TOTAL ASSETS                                                                                 $1,021,546              $1,009,509
                                                                                             ===========             ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                         AEP TEXAS NORTH COMPANY
                                                              BALANCE SHEETS
                                                      CAPITALIZATION AND LIABILITIES
                                                   June 30, 2004 and December 31, 2003
                                                               (Unaudited)

                                                                                              2004                    2003
                                                                                              ----                    ----
                                                                                                     (in thousands)
<C>                                                                                       <C>                     <C>
                           CAPITALIZATION
------------------------------------------------------------------
Common Shareholder's Equity:
   Common Stock - $25 Par Value:
     Authorized - 7,800,000 Shares
     Outstanding - 5,488,560 Shares                                                         $137,214                $137,214
      Paid-in Capital                                                                          2,351                   2,351
      Retained Earnings                                                                      144,223                 125,428
      Accumulated Other Comprehensive Income (Loss)                                          (29,882)                (26,718)
                                                                                          -----------             -----------
Total Common Shareholder's Equity                                                            253,906                 238,275
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                 2,357                   2,357
                                                                                          -----------             -----------
Total Shareholder's Equity                                                                   256,263                 240,632
Long-term Debt                                                                               314,306                 314,249
                                                                                          -----------             -----------
TOTAL                                                                                        570,569                 554,881
                                                                                          -----------             -----------

                        CURRENT LIABILITIES
------------------------------------------------------------------
Long-term Debt Due Within One Year                                                            18,469                  42,505
Accounts Payable:
  General                                                                                     21,748                  28,190
  Affiliated Companies                                                                        44,168                  40,601
Customer Deposits                                                                                998                     161
Taxes Accrued                                                                                 37,404                  22,877
Interest Accrued                                                                               5,423                   6,038
Risk Management Liabilities                                                                    7,780                   8,658
Obligations Under Capital Leases                                                                 207                     203
Other                                                                                          7,247                   9,419
                                                                                          -----------             -----------
TOTAL                                                                                        143,444                 158,652
                                                                                          -----------             -----------

              DEFERRED CREDITS AND OTHER LIABILITIES
------------------------------------------------------------------
Deferred Income Taxes                                                                        111,087                 113,019
Long-term Risk Management Liabilities                                                            639                   1,094
Regulatory Liabilities:
  Asset Removal Costs                                                                         83,601                  76,740
  Deferred Investment Tax Credits                                                             19,333                  19,990
  Retail Clawback                                                                              6,837                  11,804
  Excess Earnings                                                                             14,020                  14,262
  SFAS 109 Regulatory Liability, Net                                                          12,855                  13,655
  Other                                                                                        1,679                   1,826
Obligations Under Capital Leases                                                                 282                     270
Deferred Credits and Other                                                                    57,200                  43,316
                                                                                          -----------             -----------
TOTAL                                                                                        307,533                 295,976
                                                                                          -----------             -----------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                      $1,021,546              $1,009,509
                                                                                          ===========             ===========

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


                                                          AEP TEXAS NORTH COMPANY
                                                          STATEMENTS OF CASH FLOWS
                                              For the Six Months Ended June 30, 2004 and 2003
                                                                (Unaudited)

                                                                                                     2004                2003
                                                                                                     ----                ----
                                                                                                          (in thousands)
<C>                                                                                                 <C>                 <C>
                 OPERATING ACTIVITIES
-------------------------------------------------------
Net Income                                                                                          $20,847             $27,758
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Cumulative Effect of Accounting Changes                                                                -              (3,071)
   Depreciation and Amortization                                                                     19,546              19,255
   Deferred Income Taxes                                                                             (2,767)             (1,079)
   Deferred Investment Tax Credits                                                                     (656)               (760)
   Deferred Property Taxes                                                                           (7,400)             (6,645)
   Mark-to-Market of Risk Management Contracts                                                        1,955              (2,905)
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                                             281              24,683
   Fuel, Materials and Supplies                                                                       2,320               4,308
   Accounts Payable                                                                                  (2,875)            (61,985)
   Taxes Accrued                                                                                     14,527              16,134
Change in Other Assets                                                                               (8,931)             (5,976)
Change in Other Liabilities                                                                          14,538              12,909
                                                                                                    --------            --------
Net Cash Flows From Operating Activities                                                             51,385              22,626
                                                                                                    --------            --------

                 INVESTING ACTIVITIES
-------------------------------------------------------
Construction Expenditures                                                                           (18,085)            (21,609)
Change in Other Cash Deposits, Net                                                                      566              (1,383)
Other                                                                                                     -                 595
                                                                                                    --------            --------
Net Cash Flows Used For Investing Activities                                                        (17,519)            (22,397)
                                                                                                    --------            --------
                 FINANCING ACTIVITIES
-------------------------------------------------------
Change in Short-term Debt - Affiliates                                                                    -            (125,000)
Issuance of Long-term Debt                                                                                -             222,455
Retirement of Long-term Debt                                                                        (24,036)                  -
Change in Advances to Affiliates                                                                     (6,391)            (92,312)
Dividends Paid on Common Stock                                                                       (2,000)             (4,970)
Dividends Paid on Cumulative Preferred Stock                                                            (52)                (52)
                                                                                                    --------            --------
Net Cash Flows From (Used For) Financing Activities                                                 (32,479)                121
                                                                                                    --------            --------

Net Increase in Cash and Cash Equivalents                                                             1,387                 350
Cash and Cash Equivalents at Beginning of Period                                                          -                  62
                                                                                                    --------            --------
Cash and Cash Equivalents at End of Period                                                           $1,387                $412
                                                                                                    ========            ========


SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $11,139,000 and $5,525,000 and for income taxes was $(412,000)
and $(1,305,000) in 2004 and 2003, respectively.

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


                             AEP TEXAS NORTH COMPANY
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to TNC's financial statements are combined with the notes to
financial statements for other subsidiary registrants. Listed below are the
notes that apply to TNC. The footnotes begin on page L-1.

                                                                   Footnote
                                                                   Reference
                                                                   ---------

Significant Accounting Matters                                     Note 1

New Accounting Pronouncements                                      Note 2

Rate Matters                                                       Note 3

Customer Choice and Industry Restructuring                         Note 4

Commitments and Contingencies                                      Note 5

Guarantees                                                         Note 6

Benefit Plans                                                      Note 8

Business Segments                                                  Note 9

Financing Activities                                               Note 10


<PAGE>








                            APPALACHIAN POWER COMPANY
                                AND SUBSIDIARIES



<PAGE>


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                 ----------------------------------------------

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

Net Income for the second quarter of 2004 increased $7 million from the prior
year period due to favorable results from risk management activities, increased
sales and decreased interest charges partially offset by increased Maintenance
expense and Income Taxes.

Net Income for the first six months of 2004 decreased $84 million from the prior
year period primarily due to the Cumulative Effect of Accounting Changes of $77
million recorded in 2003 and increased Maintenance and depreciation expenses
partially offset by favorable results from risk management activities and
decreased interest charges.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income for 2004 decreased $3 million from 2003 primarily due to the
following:

 o  A decrease in off-system sales and transmission revenues totaling $10
    million.
 o  An increase in Maintenance expense of $16 million primarily due to planned
    maintenance at Amos, Clinch River, and Glen Lyn plants relating to scheduled
    outages in 2004.
 o  An $8 million increase in Income Taxes (see "Income Taxes" below).
 o  A decrease of $4 million in Sales to AEP Affiliates due to decreased power
    available for sale caused by planned plant outages in 2004.
 o  An increase in Other Operation  expense of $4 million  primarily due to
    increased  allocated costs from AEPSC and higher employee-related benefits
    costs in the second quarter of 2004.

The decrease in Operating Income for 2004 was partially offset by:

 o  An increase in retail sales of $22 million primarily as a result of
    increased cooling degree days in the second quarter of 2004.
 o  An increase of $13 million due to favorable results from risk management
    activities.
 o  A net $7 million decrease in Fuel and purchased electricity expense as a
    $14 million decrease in Fuel expense was partially offset by increased
    purchased electricity expense. The $14 million decrease in Fuel expense was
    primarily due to decreased generation and deferred fuel expense partially
    offset by the increased cost of coal used in generation.

Other Impacts on Earnings
-------------------------

Nonoperating Income (Loss) increased $4 million in 2004 compared to 2003
primarily due to favorable results from risk management activities.

Interest charges decreased $9 million in the second quarter of 2004 from the
prior year period due to reduced interest rates from refunding higher cost debt
and increased Allowance for Funds Used During Construction in 2004.

Income Taxes
------------
The effective tax rates for the second quarter of 2004 and 2003 were 46.0% and
39.9%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The increase in the effective tax rate is primarily due to
an investment tax credit adjustment as a result of the Virginia SCC extending
the regulatory transition period offset by lower state income taxes.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income for 2004 decreased $28 million from 2003 primarily due to the
following:

 o  A decrease in off-system sales and transmission revenues totaling
    $6 million.
 o  An increase in Maintenance  expense of $25 million primarily due to planned
    maintenance at Amos, Clinch River, Glen Lyn and Kanawha River plants
    relating to scheduled outages in 2004.
 o  A decrease of $7 million in Sales to AEP Affiliates due to decreased power
    available for sale caused by planned plant outages in 2004.
 o  An increase in Depreciation and Amortization expense of $13 million
    primarily due to reduced expense in 2003 attributable to the adoption of
    SFAS 143 for regulated operations and to a lesser degree, a greater
    depreciable base in 2004, which included the addition of capitalized
    software costs.
 o  An increase in Other Operation expense of $10 million primarily due to
    increased allocated costs from AEPSC and higher employee-related benefits
    costs in 2004.

The decrease in Operating Income for 2004 was partially offset by:

 o  An increase in retail sales of $22 million primarily as a result of
    increased cooling degree days in the second quarter of 2004.
 o  A net $7 million decrease in Fuel and purchased electricity expense as a
    $23 million decrease in Fuel expense was partially offset by increased
    purchased electricity expense. The $23 million decrease in Fuel expense was
    primarily due to decreased generation and deferred fuel expense partially
    offset by the increased cost of coal used in generation.

Other Impacts on Earnings
-------------------------

Nonoperating Income (Loss) increased $14 million in 2004 compared to 2003
primarily due to favorable results from risk management activities.

Interest charges decreased $12 million in the first six months of 2004 from the
prior year due to reduced interest rates from refunding higher cost debt and
increased Allowance for Funds Used During Construction in 2004.

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were 40.2% and
37.3%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The increase in the effective tax rate is primarily due to
an investment tax credit adjustment as a result of the Virginia SCC extending
the regulatory transition period offset by federal income tax adjustments.

Cumulative Effect of Accounting Changes
---------------------------------------

The Cumulative Effect of Accounting Changes of $77 million is due to the
implementation of SFAS 143 and EITF 02-3 in 2003.

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+

Cash Flow
---------

Cash flows for the six months ended June 30, 2004 and 2003 were as follows:

<TABLE>
<CAPTION>

                                                                           2004              2003
                                                                           ----              ----
                                                                               (in thousands)

<C>                                                                     <C>               <C>
Cash and cash equivalents at beginning of period                          $4,561            $4,133
                                                                        ---------         ---------
Cash flow from (used for):
  Operating activities                                                   228,942           267,383
  Investing activities                                                  (163,031)         (113,170)
  Financing activities                                                   (66,841)         (147,840)
                                                                        ---------         ---------
Net increase (decrease) in cash and cash equivalents                        (930)            6,373
                                                                        ---------         ---------
Cash and cash equivalents at end of period                                $3,631           $10,506
                                                                        =========         =========

</TABLE>

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

Net Cash Flows From Operating Activities in the first six months of 2004 were
$229 million versus $267 million in 2003 due to changes in Accounts Receivable
and Accounts Payable, as well as increased purchases of emission allowances and
increased fuel inventory.

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

Net Cash Flows Used For Investing Activities in the first six months of 2004
were $163 million. Current year construction expenditures of $204 million were
focused primarily on projects to improve service reliability for transmission
and distribution, as well as environmental upgrades. In addition, Changes in
Other Cash Deposits, Net of $41 million consisted primarily of monies set aside
in 2003 for the retirement of the Installment Purchase Contracts in 2004.

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

In the first six months of 2004, we retired $40 million of Installment Purchase
Contracts and $45 million of First Mortgage Bonds, paid $50 million in dividends
and increased Advances from Affiliates by $69 million.

Financing Activity
------------------

Long-term debt issuances and retirements during the first six months of 2004
were:

    Issuances
    ---------

     None.

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

     First Mortgage Bonds           $45,000           7.125           2024
     Installment Purchase
       Contracts                     40,000           5.45            2019

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

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report 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
------------

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

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

                                      MTM Risk Management Contract Net Assets
                                          Six Months Ended June 30, 2004
                                                  (in thousands)

 <C>                                                                                                        <C>
 Total MTM Risk Management Contract Net Assets at December 31, 2003                                         $68,066
 (Gain) Loss from Contracts Realized/Settled During the Period (a)                                          (23,158)
 Fair Value of New Contracts When Entered Into During the Period (b)                                              -
 Net Option Premiums Paid/(Received) (c)                                                                        601
 Change in Fair Value Due to Valuation Methodology Changes (d)                                                  835
 Changes in Fair Value of Risk Management Contracts (e)                                                       5,166
 Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f)                     5,782
                                                                                                            --------
 Total MTM Risk Management Contract Net Assets                                                               57,292
 Net Cash Flow Hedge Contracts (g)                                                                           (6,972)
 DETM Assignment (h)                                                                                        (27,127)
                                                                                                            --------
 Total MTM Risk Management Contract Net Assets at June 30, 2004                                             $23,193
                                                                                                            ========
</TABLE>

(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
    includes realized risk management contracts and related derivatives
    that settled during 2004 that were entered into prior to 2004.
(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 2004. 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 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
    represents the impact of AEP changes in methodology in regards to
    credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
    fair value change in the risk management portfolio due to market
    fluctuations during the current period. Market fluctuations are
    attributable to various factors such as supply/demand, weather, etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
    Regulated Jurisdictions" relates to the net gains (losses) of those
    contracts that are not reflected in the Consolidated Statements of
    Income. These net gains (losses) are recorded as regulatory
    liabilities/assets for those subsidiaries that operate in regulated
    jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
    Accumulated Other Comprehensive Income (Loss).
(h) See Note 17 "Related Party Transactions" in the 2003 Annual Report.

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

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

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

<TABLE>
<CAPTION>

                                                Maturity and Source of Fair Value of MTM
                                                   Risk Management Contract Net Assets
                                              Fair Value of Contracts as of June 30, 2004

                                                  Remainder                                                      After
                                                     2004        2005         2006       2007         2008       2008    Total (c)
                                                  ---------      ----         ----       ----         ----       -----   ---------
                                                                                    (in thousands)
<C>                                               <C>          <C>          <C>         <C>         <C>        <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                                 $(3,646)        $362        $(10)     $1,156          $-         $-     $(2,138)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                   16,350        5,240       3,670       1,978         928          -      28,166
Prices Based on Models and Other Valuation
 Methods (b)                                          289        5,929       2,754       4,839       4,912      12,541     31,264
                                                  --------     --------     -------     -------     -------    --------   --------

Total                                             $12,993      $11,531      $6,414      $7,973      $5,840     $12,541    $57,292
                                                  ========     ========     =======     =======     =======    ========   ========
</TABLE>

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

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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be market-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.

<TABLE>
<CAPTION>

                                 Total Accumulated Other Comprehensive Income (Loss) Activity
                                              Six Months Ended June 30, 2004

                                                                     Foreign
                                                    Power           Currency            Interest Rate       Consolidated
                                                    -----           --------            -------------       ------------
                                                                            (in thousands)

<C>                                               <C>                <C>                  <C>                <C>
Beginning Balance December 31, 2003                  $359            $(183)               $(1,745)           $(1,569)
Changes in Fair Value (a)                          (2,971)               -                   (705)            (3,676)
Reclassifications from AOCI to Net
 Income (b)                                          (958)               3                    169               (786)
                                                  --------           ------               --------           --------
Ending Balance June 30, 2004                      $(3,570)           $(180)               $(2,281)           $(6,031)
                                                  ========           ======               ========           ========

</TABLE>

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

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $2,659 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:

        Six Months Ended                          Twelve Months Ended
         June 30, 2004                             December 31, 2003
        ----------------                          -------------------
         (in thousands)                             (in thousands)

End     High     Average    Low              End     High   Average    Low
---     ----     -------    ---              ---     ----   -------    ---
$936   $2,122    $1,056    $529              $596   $2,314   $969     $230


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $111 million and $102 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period; therefore, a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.


<PAGE>
<TABLE>
<CAPTION>


                                          APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                              CONSOLIDATED STATEMENTS OF INCOME
                                 For the Three and Six Months Ended June 30, 2004 and 2003
                                                          (Unaudited)

                                                                           Three Months Ended                Six Months Ended
                                                                          --------------------            ----------------------
                                                                          2004            2003            2004              2003
                                                                          ----            ----            ----              ----
                                                                                              (in thousands)
<C>                                                                     <C>             <C>              <C>              <C>
                    OPERATING REVENUES
----------------------------------------------------------
Electric Generation, Transmission and Distribution                      $413,383        $389,255         $885,958         $868,588
Sales to AEP Affiliates                                                   51,047          55,496          104,929          112,391
                                                                        ---------       ---------        ---------        ---------
TOTAL                                                                    464,430         444,751          990,887          980,979
                                                                        ---------       ---------        ---------        ---------

                    OPERATING EXPENSES
----------------------------------------------------------
Fuel for Electric Generation                                              98,694         112,680          209,405          232,545
Purchased Electricity for Resale                                          17,786          15,262           34,430           32,380
Purchased Electricity from AEP Affiliates                                 87,793          83,805          178,280          164,525
Other Operation                                                           70,576          66,626          138,668          128,741
Maintenance                                                               52,933          36,827           94,253           69,565
Depreciation and Amortization                                             47,231          46,065           95,144           82,073
Taxes Other Than Income Taxes                                             23,499          22,272           46,952           47,351
Income Taxes                                                              19,836          12,158           60,276           62,059
                                                                        ---------       ---------        ---------        ---------
TOTAL                                                                    418,348         395,695          857,408          819,239
                                                                        ---------       ---------        ---------        ---------

OPERATING INCOME                                                          46,082          49,056          133,479          161,740

Nonoperating Income (Loss)                                                 3,540            (324)           9,087           (4,624)
Nonoperating Expenses                                                      3,596           2,451            6,129            6,309
Nonoperating Income Tax Credit                                            (1,263)         (2,451)          (1,625)          (6,184)
Interest Charges                                                          25,463          34,096           50,900           63,202
                                                                        ---------       ---------        ---------        ---------

Income Before Cumulative Effect of Accounting Changes                     21,826          14,636           87,162           93,789
Cumulative Effect of Accounting Changes (Net of Tax)                           -               -                -           77,257
                                                                        ---------       ---------        ---------        ---------

NET INCOME                                                                21,826          14,636           87,162          171,046

Preferred Stock Dividend Requirements (Including Capital
 Stock Expense)                                                              798             984            1,621            1,968
                                                                        ---------       ---------        ---------        ---------

EARNINGS APPLICABLE TO COMMON STOCK                                      $21,028         $13,652          $85,541         $169,078
                                                                        =========       =========        =========        =========

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

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


                                                 APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                         CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                     EQUITY AND COMPREHENSIVE INCOME
                                             For the Six Months Ended June 30, 2004 and 2003
                                                            (in thousands)
                                                              (Unaudited)


                                                                                                   Accumulated Other
                                                       Common         Paid-in        Retained        Comprehensive
                                                       Stock          Capital        Earnings        Income (Loss)         Total
                                                       ------         -------        --------      -----------------       -----
<C>                                                   <C>            <C>             <C>                 <C>            <C>
DECEMBER 31, 2002                                     $260,458       $717,242        $260,439            $(72,082)      $1,166,057

Common Stock Dividends                                                                (64,133)                             (64,133)
Preferred Stock Dividends                                                                (721)                                (721)
Capital Stock Expense                                                   1,247          (1,247)                                   -
SFAS 71 Reapplication                                                     162                                                  162
                                                                                                                        -----------
TOTAL                                                                                                                    1,101,365
                                                                                                                        -----------

        COMPREHENSIVE INCOME
------------------------------------
Other Comprehensive Income (Loss),
 Net of  Taxes:
  Cash Flow Hedges                                                                                         (3,113)          (3,113)
NET INCOME                                                                            171,046                              171,046
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                 167,933
                                                      ---------      ---------       ---------           ---------      -----------
JUNE 30, 2003                                         $260,458       $718,651        $365,384            $(75,195)      $1,269,298
                                                      =========      =========       =========           =========      ===========


DECEMBER 31, 2003                                     $260,458       $719,899        $408,718            $(52,088)      $1,336,987

Common Stock Dividends                                                                (50,000)                             (50,000)
Preferred Stock Dividends                                                                (400)                                (400)
Capital Stock Expense                                                   1,221          (1,221)                                   -
                                                                                                                        -----------
TOTAL                                                                                                                    1,286,587
                                                                                                                        -----------

        COMPREHENSIVE INCOME
------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
  Cash Flow Hedges                                                                                         (4,462)          (4,462)
NET INCOME                                                                             87,162                               87,162
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                  82,700
                                                      ---------      ---------       ---------           ---------      -----------
JUNE 30, 2004                                         $260,458       $721,120        $444,259            $(56,550)      $1,369,287
                                                      =========      =========       =========           =========      ===========

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


                                                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                      CONSOLIDATED BALANCE SHEETS
                                                                 ASSETS
                                                    June 30, 2004 and December 31, 2003
                                                               (Unaudited)

                                                                                              2004                 2003
                                                                                              ----                 ----
                                                                                                    (in thousands)
<C>                                                                                        <C>                    <C>

                  ELECTRIC UTILITY PLANT
-------------------------------------------------------
Production                                                                                 $2,408,222             $2,287,043
Transmission                                                                                1,249,901              1,240,889
Distribution                                                                                2,033,834              2,006,329
General                                                                                       302,053                294,786
Construction Work in Progress                                                                 321,620                311,884
                                                                                           -----------            -----------
TOTAL                                                                                       6,315,630              6,140,931
Accumulated Depreciation and Amortization                                                   2,382,795              2,321,360
                                                                                           -----------            -----------
TOTAL - NET                                                                                 3,932,835              3,819,571
                                                                                           -----------            -----------

             OTHER PROPERTY AND INVESTMENTS
-------------------------------------------------------
Non-Utility Property, Net                                                                      20,457                 20,574
Other Investments                                                                              22,938                 26,668
                                                                                           -----------            -----------
TOTAL                                                                                          43,395                 47,242
                                                                                           -----------            -----------

                      CURRENT ASSETS
-------------------------------------------------------
Cash and Cash Equivalents                                                                       3,631                  4,561
Other Cash Deposits                                                                               705                 41,320
Accounts Receivable:
  Customers                                                                                   136,105                133,717
  Affiliated Companies                                                                        119,821                137,281
  Accrued Unbilled Revenues                                                                    23,669                 35,020
  Miscellaneous                                                                                 4,302                  3,961
  Allowance for Uncollectible Accounts                                                         (5,426)                (2,085)
Fuel Inventory                                                                                 60,580                 42,806
Materials and Supplies                                                                         87,942                 71,978
Risk Management Assets                                                                         91,267                 71,189
Margin Deposits                                                                                 3,974                 11,525
Prepayments and Other                                                                          13,317                 13,301
                                                                                           -----------            -----------
TOTAL                                                                                         539,887                564,574
                                                                                           -----------            -----------

             DEFERRED DEBITS AND OTHER ASSETS
-------------------------------------------------------
Regulatory Assets:
  Transition Regulatory Assets                                                                 27,590                 30,855
  SFAS 109 Regulatory Asset, Net                                                              324,233                325,889
  Unamortized Loss on Reacquired Debt                                                          19,696                 19,005
  Other Regulatory Assets                                                                      41,658                 41,447
Long-term Risk Management Assets                                                               83,507                 70,900
Deferred Property Taxes                                                                        29,640                 35,343
Other Deferred Charges                                                                         22,784                 22,185
                                                                                           -----------            -----------
TOTAL                                                                                         549,108                545,624
                                                                                           -----------            -----------

TOTAL ASSETS                                                                               $5,065,225             $4,977,011
                                                                                           ===========            ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                           APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                  CONSOLIDATED BALANCE SHEETS
                                                 CAPITALIZATION AND LIABILITIES
                                              June 30, 2004 and December 31, 2003
                                                          (Unaudited)


                                                                                                     2004              2003
                                                                                                     ----              ----
                                                                                                         (in thousands)
<C>                                                                                               <C>               <C>
                    CAPITALIZATION
-------------------------------------------------------
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                                                                                  721,120           719,899
    Retained Earnings                                                                                444,259           408,718
    Accumulated Other Comprehensive Income (Loss)                                                    (56,550)          (52,088)
                                                                                                  -----------       -----------
Total Common Shareholder's Equity                                                                  1,369,287         1,336,987
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                        17,784            17,784
                                                                                                  -----------       -----------
Total Shareholder's Equity                                                                         1,387,071         1,354,771
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption                               5,360             5,360
Long-term Debt                                                                                     1,128,920         1,703,073
                                                                                                  -----------       -----------
TOTAL                                                                                              2,521,351         3,063,204
                                                                                                  -----------       -----------

                 CURRENT LIABILITIES
------------------------------------------------------
Long-term Debt Due Within One Year                                                                   651,008           161,008
Advances from Affiliates                                                                             151,558            82,994
Accounts Payable:
  General                                                                                            120,705           140,497
  Affiliated Companies                                                                                65,734            81,812
Customer Deposits                                                                                     45,552            33,930
Taxes Accrued                                                                                         77,933            50,259
Interest Accrued                                                                                      22,149            22,113
Risk Management Liabilities                                                                           83,792            51,430
Obligations Under Capital Leases                                                                       7,074             9,218
Other                                                                                                 54,460            60,289
                                                                                                  -----------       -----------
TOTAL                                                                                              1,279,965           693,550
                                                                                                  -----------       -----------

         DEFERRED CREDITS AND OTHER LIABILITIES
-------------------------------------------------------
Deferred Income Taxes                                                                                823,671           803,355
Regulatory Liabilities:
  Asset Removal Costs                                                                                 95,206            92,497
  Deferred Investment Tax Credits                                                                     32,635            30,545
  Over Recovery of Fuel Cost                                                                          69,312            68,704
  Other Regulatory Liabilities                                                                        23,493            17,326
Long-term Risk Management Liabilities                                                                 67,789            54,327
Obligations Under Capital Leases                                                                      13,935            16,134
Asset Retirement Obligation                                                                           22,635            21,776
Deferred Credits and Other                                                                           115,233           115,593
                                                                                                  -----------       -----------
TOTAL                                                                                              1,263,909         1,220,257
                                                                                                  -----------       -----------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                              $5,065,225        $4,977,011
                                                                                                  ===========       ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                                      APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                        CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   For the Six Months Ended June 30, 2004 and 2003
                                                     (Unaudited)

                                                                                                2004                  2003
                                                                                                ----                  ----
                                                                                                       (in thousands)
<C>                                                                                           <C>                   <C>
                OPERATING ACTIVITIES
--------------------------------------------------------
Net Income                                                                                     $87,162              $171,046
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
    Cumulative Effect of Accounting Changes                                                          -               (77,257)
    Depreciation and Amortization                                                               95,144                82,073
    Deferred Income Taxes                                                                       24,377                 2,305
    Deferred Investment Tax Credits                                                              2,090                  (847)
    Deferred Property Taxes                                                                      5,793                 5,343
    Deferred Power Supply Costs, Net                                                               607                69,528
    Mark to Market of Risk Management Contracts                                                  5,615                19,433
Changes in Certain Assets and Liabilities:
    Accounts Receivable, Net                                                                    29,423                64,565
    Fuel, Materials and Supplies                                                               (33,738)                2,965
    Accounts Payable                                                                           (35,870)              (79,628)
    Taxes Accrued                                                                               27,674                33,303
    Interest Accrued                                                                                36                 2,255
    Incentive Plan Accrued                                                                      (1,940)               (9,388)
Rate Stabilization Deferral                                                                          -               (75,601)
Change in Other Assets                                                                           9,952                 3,483
Change in Other Liabilities                                                                     12,617                53,805
                                                                                              ---------             ---------
Net Cash Flows From Operating Activities                                                       228,942               267,383
                                                                                              ---------             ---------

               INVESTING ACTIVITIES
--------------------------------------------------------
Construction Expenditures                                                                     (204,225)             (114,806)
Proceeds from Sale of Property and Other                                                           579                 1,648
Change in Other Cash Deposits, Net                                                              40,615                   (12)
                                                                                              ---------             ---------
Net Cash Flows Used For Investing Activities                                                  (163,031)             (113,170)
                                                                                              ---------             ---------
               FINANCING ACTIVITIES
--------------------------------------------------------
Issuance of Long-term Debt                                                                           -               495,122
Retirement of Long-term Debt                                                                   (85,005)             (420,238)
Change in Advances from Affiliates, Net                                                         68,564              (157,870)
Dividends Paid on Common Stock                                                                 (50,000)              (64,133)
Dividends Paid on Cumulative Preferred Stock                                                      (400)                 (721)
                                                                                              ---------             ---------
Net Cash Flows Used For Financing Activities                                                   (66,841)             (147,840)
                                                                                              ---------             ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                              (930)                6,373
Cash and Cash Equivalents at Beginning of Period                                                 4,561                 4,133
                                                                                              ---------             ---------
Cash and Cash Equivalents at End of Period                                                      $3,631               $10,506
                                                                                              =========             =========

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $46,739,000 and $56,152,000 and for income taxes was $3,946,000 and
$21,102,000 in 2004 and 2003, respectively.

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


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to APCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below
are the notes that apply to APCo. The footnotes begin on page L-1.

                                                                 Footnote
                                                                 Reference
                                                                 ---------

Significant Accounting Matters                                   Note 1

New Accounting Pronouncements                                    Note 2

Rate Matters                                                     Note 3

Customer Choice and Industry Restructuring                       Note 4

Commitments and Contingencies                                    Note 5

Guarantees                                                       Note 6

Benefit Plans                                                    Note 8

Business Segments                                                Note 9

Financing Activities                                             Note 10




<PAGE>








                         COLUMBUS SOUTHERN POWER COMPANY
                                AND SUBSIDIARIES



<PAGE>

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

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

The increase in Net Income of $1 million in second quarter 2004 was primarily
due to a $25 million increase in operating revenue, partially offset by a $9
million increase in fuel expense and a combined $15 million increase in other
operating expenses.

The decrease in year-to-date Net Income of $19 million in 2004 compared to 2003
was primarily due to a $27 million net-of-tax Cumulative Effect of Accounting
Changes in the first quarter of 2003, a $7 million increase in fuel expense,
combined increases of $20 million in other operating expenses and a $5 million
increase in Nonoperating Income Tax Expense, which was partially offset by
increases of $28 million in operating revenues and $14 million in nonoperating
risk management activities.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income increased $1 million primarily due to:

 o  An increase of $21 million in retail electric revenues resulting from
    increased weather-related demand from residential and commercial customers
    and an increase in customer base.
 o  An increase of $10 million in operating revenues related to favorable
    results from risk management activities.

The increase in Operating Income was partially offset by:

 o  A decrease of $7 million in non-affiliated wholesale energy sales due to
    lower sales volume and the expiration of municipal contracts.
 o  An increase of $9 million in fuel expense due to increased electric
    generation and higher fuel costs per KWH.
 o  An increase of $7 million in Other Operation expense primarily relating to
    uncollectible accounts, pension plan costs and increased allocated costs
    from AEPSC.
 o  An increase of $3 million in Maintenance expense due primarily to boiler
    overhaul work from scheduled and forced outages and increased overhead
    distribution line expenses.
 o  An increase of $3 million in Depreciation and Amortization expenses due to
    a greater depreciable base in 2004, including capital software costs
    allocated from AEPSC and the increased amortization of regulatory assets
    due to a federal tax adjustment to the asset account and quarterly
    adjustments to the amortization rate.
 o  An increase of $2 million in Taxes Other than Income Taxes due to increased
    state excise taxes.

Other Impacts on Earnings
-------------------------

Nonoperating Income Tax Expense decreased $1 million. See Income Taxes section
below for further discussion.

Income Taxes
------------

The effective tax rates for the second quarter of 2004 and 2003 were 33.6% and
34.2%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to the flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The effective tax rates remained relatively flat for the
comparative period.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income increased $1 million primarily due to:

 o  An increase of $30 million in retail electric revenues resulting primarily
    from increased weather-related demand from residential and commercial
    customers during the second quarter 2004.
 o  An increase of $8 million in operating revenues related to favorable results
    from risk management activities.

The increase in Operating Income was partially offset by:

 o  A decrease of $9 million in non-affiliated wholesale energy sales due to
    lower sales volume and the expiration of municipal contracts.
 o  An increase of $7 million in Fuel for Electric Generation due to increased
    electric generation and higher fuel costs per KWH.
 o  An increase of $8 million in Other Operation expense primarily relating to
    uncollectible accounts, pension plan costs and increased allocated costs
    from AEPSC.
 o  An increase of $6 million in Maintenance expense due primarily to boiler
    overhaul work from scheduled and forced outages and increased overhead and
    underground line expenses.
 o  An increase of $6 million in Depreciation and Amortization expenses due to
    a greater depreciable base in 2004, including capital software costs
    allocated from AEPSC and the increased amortization of regulatory assets
    due to a federal tax adjustment to the asset account and quarterly
    adjustment to the amortization rate.

Other Impacts on Earnings
-------------------------

Nonoperating Income increased $12 million primarily due to favorable results
from risk management activities.

Nonoperating Income Tax Expense increased $5 million. See Income Taxes section
below for further discussion.

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were 35.1% and
34.1%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to the flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The effective tax rates remained relatively flat for the
comparative period.

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.

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-


Financing Activity
------------------

Long-term debt issuances and retirements during the first six months of 2004
were:

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


   Installment Purchase Contracts        $43,695          Variable        2038


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

   First Mortgage Bonds                  $11,000            7.60          2024
   Installment Purchase Contracts         43,695            6.25          2020


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

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report 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
------------

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

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

                                    MTM Risk Management Contract Net Assets
                                       Six Months Ended June 30, 2004
                                               (in thousands)

<C>                                                                                                        <C>
 Total MTM Risk Management Contract Net Assets at December 31, 2003                                        $38,337
 (Gain) Loss from Contracts Realized/Settled During the Period (a)                                         (13,471)
 Fair Value of New Contracts When Entered Into During the Period (b)                                             -
 Net Option Premiums Paid/(Received) (c)                                                                       369
 Change in Fair Value Due to Valuation Methodology Changes (d)                                                 898
 Changes in Fair Value of Risk Management Contracts (e)                                                      9,080
 Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f)                        -
                                                                                                           --------
 Total MTM Risk Management Contract Net Assets                                                              35,213
 Net Cash Flow Hedge Contracts (g)                                                                          (3,375)
 DETM Assignment (h)                                                                                       (16,673)
                                                                                                           --------
 Total MTM Risk Management Contract Net Assets at June 30, 2004                                            $15,165
                                                                                                           ========
</TABLE>

(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
    includes realized risk management contracts and related derivatives
    that settled during 2004 that were entered into prior to 2004.
(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 2004. 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 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
    represents the impact of AEP changes in methodology in regards to
    credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
    fair value change in the risk management portfolio due to market
    fluctuations during the current period. Market fluctuations are
    attributable to various factors such as supply/demand, weather, etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
    Regulated Jurisdictions" relates to the net gains (losses) of those
    contracts that are not reflected in the Consolidated Statements of
    Income. These net gains (losses) are recorded as regulatory
    liabilities/assets for those subsidiaries that operate in regulated
    jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
    Accumulated Other Comprehensive Income (Loss).
(h) See Note 17 "Related Party Transactions" in the 2003 Annual Report.


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

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

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

<TABLE>
<CAPTION>

                                               Maturity and Source of Fair Value of MTM
                                                 Risk Management Contract Net Assets
                                             Fair Value of Contracts as of June 30, 2004

                                            Remainder                                                         After
                                              2004          2005         2006         2007        2008        2008    Total (c)
                                            ---------       ----         ----         ----        ----        ----    ---------
                                                                                (in thousands)
<C>                                         <C>           <C>          <C>          <C>         <C>          <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                           $(2,241)        $223          $(6)        $711          $-           $-     $(1,313)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)             10,050        3,220        2,256        1,216         570            -      17,312
Prices Based on Models and Other
 Valuation Methods (b)                          175        3,644        1,693        2,974       3,020        7,708      19,214
                                            --------      -------      -------      -------     -------      -------    --------

Total                                        $7,984       $7,087       $3,943       $4,901      $3,590       $7,708     $35,213
                                            ========      =======      =======      =======     =======      =======    ========

</TABLE>

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


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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.

          Total Accumulated Other Comprehensive Income (Loss) Activity
                         Six Months Ended June 30, 2004

                                                                  Power
                                                                  -----
                                                              (in thousands)
       Beginning Balance December 31, 2003                         $202
       Changes in Fair Value (a)                                 (1,796)
       Reclassifications from AOCI to Net Income (b)               (601)
                                                                --------
       Ending Balance June 30, 2004                             $(2,195)
                                                                ========

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

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,404 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

VaR Associated with Energy and Gas Risk Management Contracts

The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:

        Six Months Ended                          Twelve Months Ended
         June 30, 2004                             December 31, 2003
        ----------------                          -------------------
         (in thousands)                             (in thousands)

End     High     Average    Low              End     High   Average    Low
---     ----     -------    ---              ---     ----   -------    ---
$575   $1,304     $649     $325              $336   $1,303   $546     $130


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $85 million and $98 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.


<PAGE>
<TABLE>
<CAPTION>


                                            COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                   CONSOLIDATED STATEMENTS OF INCOME
                                       For the Three and Six Months Ended June 30, 2004 and 2003
                                                              (Unaudited)

                                                                           Three Months Ended               Six Months Ended
                                                                          --------------------            ---------------------
                                                                          2004            2003            2004             2003
                                                                          ----            ----            ----             ----
                                                                                           (in thousands)
<C>                                                                     <C>             <C>              <C>             <C>
                OPERATING REVENUES
-----------------------------------------------------
Electric Generation, Transmission and Distribution                      $336,793        $313,359         $680,479        $651,796
Sales to AEP Affiliates                                                   21,333          19,712           39,952          40,480
                                                                        ---------       ---------        ---------       ---------
TOTAL                                                                    358,126         333,071          720,431         692,276
                                                                        ---------       ---------        ---------       ---------
                OPERATING EXPENSES
-----------------------------------------------------
Fuel for Electric Generation                                              51,159          37,924           92,796          85,464
Fuel From Affiliates for Electric Generation                               1,755           6,100           10,603          10,603
Purchased Electricity for Resale                                           4,769           4,012            9,450           8,210
Purchased Electricity from AEP Affiliates                                 85,706          87,590          167,421         169,739
Other Operation                                                           58,796          52,294          116,277         108,679
Maintenance                                                               25,944          22,612           42,770          37,171
Depreciation and Amortization                                             36,445          33,299           73,263          67,036
Taxes Other Than Income Taxes                                             32,726          30,954           68,052          66,562
Income Taxes                                                              16,197          14,869           40,662          40,244
                                                                        ---------       ---------        ---------       ---------
TOTAL                                                                    313,497         289,654          621,294         593,708
                                                                        ---------       ---------        ---------       ---------

OPERATING INCOME                                                          44,629          43,417           99,137          98,568

Nonoperating Income (Loss)                                                   770             311            5,848          (6,365)
Nonoperating Expenses                                                        859             584            1,593           2,785
Nonoperating Income Tax Expense (Credit)                                    (628)            400              291          (5,147)
Interest Charges                                                          14,413          13,413           27,227          26,875
                                                                        ---------       ---------        ---------       ---------

Income Before Cumulative Effect of Accounting Changes                     30,755          29,331           75,874          67,690
Cumulative Effect of Accounting Changes (Net of Tax)                           -               -                -          27,283
                                                                        ---------       ---------        ---------       ---------

NET INCOME                                                                30,755          29,331           75,874          94,973

Preferred Stock - Capital Stock Expense                                      254             254              508             508
                                                                        ---------       ---------        ---------       ---------

EARNINGS APPLICABLE TO COMMON STOCK                                      $30,501         $29,077          $75,366         $94,465
                                                                        =========       =========        =========       =========

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

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

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


                                        COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                  CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                               EQUITY AND COMPREHENSIVE INCOME
                                        For the Six Months Ended June 30, 2004 and 2003
                                                        (in thousands)
                                                         (Unaudited)


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

<C>                                                 <C>           <C>              <C>                 <C>             <C>
DECEMBER 31, 2002                                   $41,026       $575,384         $290,611            $(59,357)       $847,664

Common Stock Dividends Declared                                                     (86,622)                            (86,622)
Capital Stock Expense                                                  508             (508)                                  -
                                                                                                                       ---------
TOTAL                                                                                                                   761,042
                                                                                                                       ---------

           COMPREHENSIVE INCOME
-------------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Cash Flow Hedges                                                                                      (1,193)         (1,193)
 NET INCOME                                                                          94,973                              94,973
                                                                                                                       ---------
 TOTAL COMPREHENSIVE INCOME                                                                                              93,780
                                                    --------      ---------        ---------           ---------       ---------
JUNE 30, 2003                                       $41,026       $575,892         $298,454            $(60,550)       $854,822
                                                    ========      =========        =========           =========       =========

DECEMBER 31, 2003                                   $41,026       $576,400         $326,782            $(46,327)       $897,881

Common Stock Dividends Declared                                                     (62,500)                            (62,500)
Capital Stock Expense                                                  508             (508)                                  -
                                                                                                                       ---------
TOTAL                                                                                                                   835,381
                                                                                                                       ---------

           COMPREHENSIVE INCOME
-------------------------------------------
Other Comprehensive Income (Loss),
  Net of Taxes:
    Cash Flow Hedges                                                                                     (2,397)         (2,397)
 NET INCOME                                                                          75,874                              75,874
                                                                                                                       ---------
 TOTAL COMPREHENSIVE INCOME                                                                                              73,477
                                                    --------      ---------        ---------           ---------       ---------
JUNE 30, 2004                                       $41,026       $576,908         $339,648            $(48,724)       $908,858
                                                    ========      =========        =========           =========       =========

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


                                           COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                    CONSOLIDATED BALANCE SHEETS
                                                              ASSETS
                                                 June 30, 2004 and December 31, 2003
                                                           (Unaudited)

                                                                                                 2004                    2003
                                                                                                 ----                    ----
                                                                                                         (in thousands)
<C>                                                                                           <C>                     <C>
                 ELECTRIC UTILITY PLANT
-----------------------------------------------------
Production                                                                                    $1,645,647              $1,610,888
Transmission                                                                                     429,803                 425,512
Distribution                                                                                   1,274,698               1,253,760
General                                                                                          169,716                 166,002
Construction Work in Progress                                                                    103,740                 114,281
                                                                                              -----------             -----------
TOTAL                                                                                          3,623,604               3,570,443
Accumulated Depreciation and Amortization                                                      1,430,860               1,389,586
                                                                                              -----------             -----------
TOTAL - NET                                                                                    2,192,744               2,180,857
                                                                                              -----------             -----------

             OTHER PROPERTY AND INVESTMENTS
-----------------------------------------------------
Non-Utility Property, Net                                                                         21,771                  22,417
Other Investments                                                                                  6,889                   8,663
                                                                                              -----------             -----------
TOTAL                                                                                             28,660                  31,080
                                                                                              -----------             -----------

                    CURRENT ASSETS
-----------------------------------------------------
Cash and Cash Equivalents                                                                          2,943                   3,377
Other Cash Deposits                                                                                  747                     765
Accounts Receivable:
  Customers                                                                                       43,660                  47,099
  Affiliated Companies                                                                            54,861                  68,168
  Accrued Unbilled Revenues                                                                       19,388                  23,723
  Miscellaneous                                                                                    6,533                   5,257
  Allowance for Uncollectible Accounts                                                            (1,209)                   (531)
Fuel                                                                                              26,019                  14,365
Materials and Supplies                                                                            66,754                  44,377
Risk Management Assets                                                                            55,556                  40,095
Margin Deposits                                                                                    2,500                   6,636
Prepayments and Other                                                                             12,681                  12,444
                                                                                              -----------             -----------
TOTAL                                                                                            290,433                 265,775
                                                                                              -----------             -----------

            DEFERRED DEBITS AND OTHER ASSETS
-----------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Assets, Net                                                                 16,209                  16,027
  Transition Regulatory Assets                                                                   172,780                 188,532
  Unamortized Loss on Reacquired Debt                                                             13,538                  13,659
  Other                                                                                           22,477                  24,966
Long-term Risk Management Assets                                                                  51,328                  39,932
Deferred Property Taxes                                                                           31,499                  62,262
Deferred Charges                                                                                  17,644                  15,276
                                                                                              -----------             -----------
TOTAL                                                                                            325,475                 360,654
                                                                                              -----------             -----------

TOTAL ASSETS                                                                                  $2,837,312              $2,838,366
                                                                                              ===========             ===========

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

                                            COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                      CONSOLIDATED BALANCE SHEETS
                                                     CAPITALIZATION AND LIABILITIES
                                                   June 30, 2004 and December 31, 2003
                                                              (Unaudited)
                                                                                                  2004                    2003
                                                                                                  -----                   ----
                                                                                                          (in thousands)
<C>                                                                                           <C>                      <C>
                CAPITALIZATION
---------------------------------------------------
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                                                                             576,908                  576,400
     Retained Earnings                                                                           339,648                  326,782
     Accumulated Other Comprehensive Income (Loss)                                               (48,724)                 (46,327)
                                                                                              -----------              -----------
Total Common Shareholder's Equity                                                                908,858                  897,881
Long-term Debt                                                                                   838,654                  886,564
                                                                                              -----------              -----------
TOTAL                                                                                          1,747,512                1,784,445
                                                                                              -----------              -----------

               CURRENT LIABILITIES
---------------------------------------------------
Long-term Debt Due Within One Year                                                                48,550                   11,000
Advances from Affiliates, Net                                                                      5,959                    6,517
Accounts Payable:
  General                                                                                         51,619                   58,220
  Affiliated Companies                                                                            40,089                   53,572
Customer Deposits                                                                                 26,472                   19,727
Taxes Accrued                                                                                    114,063                  132,853
Interest Accrued                                                                                  16,533                   16,528
Risk Management Liabilities                                                                       50,829                   28,966
Obligations Under Capital Leases                                                                   3,834                    4,221
Other                                                                                             22,858                   25,364
                                                                                              -----------              -----------
TOTAL                                                                                            380,806                  356,968
                                                                                              -----------              -----------

       DEFERRED CREDITS AND OTHER LIABILITIES
---------------------------------------------------
Deferred Income Taxes                                                                            466,032                  458,498
Regulatory Liabilities:
  Asset Removal Costs                                                                            101,441                   99,119
  Deferred Investment Tax Credits                                                                 29,324                   30,797
Long-term Risk Management Liabilities                                                             40,890                   30,598
Obligations Under Capital Leases                                                                   9,672                   11,397
Asset Retirement Obligations                                                                       9,085                    8,740
Deferred Credits and Other                                                                        52,550                   57,804
                                                                                              -----------              -----------
TOTAL                                                                                            708,994                  696,953
                                                                                              -----------              -----------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                          $2,837,312               $2,838,366
                                                                                              ===========              ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.

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


                                              COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                              For the Six Months Ended June 30, 2004 and 2003
                                                                (Unaudited)

                                                                                                 2004                   2003
                                                                                                 ----                   ----
                                                                                                       (in thousands)
<C>                                                                                             <C>                   <C>
              OPERATING ACTIVITIES
------------------------------------------------------
Net Income                                                                                      $75,874               $94,973
Adjustments to Reconcile Net Income to Net Cash Flows
   From Operating Activities:
     Cumulative Effect of Accounting Changes                                                          -               (27,283)
     Depreciation and Amortization                                                               73,263                67,036
     Deferred Income Taxes                                                                        8,642                (3,135)
     Deferred Investment Tax Credits                                                             (1,473)               (1,526)
     Deferred Property Taxes                                                                     31,039                30,973
     Mark-to-Market of Risk Management Contracts                                                  1,611                19,215
     Gain on Sale of Assets                                                                      (1,786)                    -
Changes in Certain Assets and Liabilities:
     Accounts Receivable, Net                                                                    20,483                34,337
     Fuel, Materials and Supplies                                                               (34,031)                1,005
     Accounts Payable                                                                           (20,084)              (39,326)
     Taxes Accrued                                                                              (18,790)              (24,796)
     Interest Accrued                                                                                 5                 7,669
Change in Other Assets                                                                            3,976                (9,835)
Change in Other Liabilities                                                                         360                   502
                                                                                                --------              --------
Net Cash Flows From Operating Activities                                                        139,089               149,809
                                                                                                --------              --------

               INVESTING ACTIVITIES
------------------------------------------------------
Construction Expenditures                                                                       (67,148)              (65,492)
Proceeds from Sale of Property and Other                                                          2,265                   190
Change in Other Cash Deposits, Net                                                                   18                    (6)
                                                                                                --------              --------
Net Cash Flows Used For Investing Activities                                                    (64,865)              (65,308)
                                                                                                --------              --------
               FINANCING ACTIVITIES
------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated                                                       43,095               494,350
Change in Advances to/from Affiliates, Net                                                         (558)              146,271
Retirement of Long-term Debt - Nonaffiliated                                                    (54,695)             (182,500)
Retirement of Long-term Debt - Affiliated                                                             -              (160,000)
Change in Short-term Debt - Affiliates                                                                -              (290,000)
Dividends Paid on Common Stock                                                                  (62,500)              (86,622)
                                                                                                --------              --------
Net Cash Flows Used For Financing Activities                                                    (74,658)              (78,501)
                                                                                                --------              --------

Net Increase (Decrease) in Cash and Cash Equivalents                                               (434)                6,000
Cash and Cash Equivalents at Beginning of Period                                                  3,377                   697
                                                                                                --------              --------
Cash and Cash Equivalents at End of Period                                                       $2,943                $6,697
                                                                                                ========              ========

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $25,131,000 and $18,442,000 and for income taxes was $(3,747,000)
and $(9,245,000) in 2004 and 2003, respectively.

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




                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to CSPCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below
are the notes that apply to CSPCo. The footnotes begin on page L-1.

                                                                   Footnote
                                                                   Reference
                                                                   ---------

Significant Accounting Matters                                     Note 1

New Accounting Pronouncements                                      Note 2

Rate Matters                                                       Note 3

Customer Choice and Industry Restructuring                         Note 4

Commitments and Contingencies                                      Note 5

Guarantees                                                         Note 6

Benefit Plans                                                      Note 8

Business Segments                                                  Note 9

Financing Activities                                               Note 10



<PAGE>









                         INDIANA MICHIGAN POWER COMPANY
                                AND SUBSIDIARIES



<PAGE>

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

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

Net Income increased $28 million for the second quarter of 2004 and $44 million
for the first six months of 2004. The increases in Net Income reflect
improvement in retail sales, the end of amortization of Cook Plant outage
settlements and reduced financing charges in both the quarter and year-to-date
periods and favorable results from risk management activities for the
year-to-date period.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income increased $24 million primarily due to:

 o  An $18 million increase in retail revenues due primarily to a
    weather-related increase in residential and commercial sales, an
    improvement in industrial sales reflecting the recovering economy and the
    end of amortization of Cook outage settlements.
 o  A $6 million increase in wholesale sales, including favorable results from
    risk management activities.
 o  The  increased  availability of the Cook Plant that resulted in a $5
    million increase in Sales to Affiliates and an $8 million  decrease in
    Purchased Electricity from AEP affiliates.

The increase in Operating Income was partially offset by:

 o  A $4 million increase in Maintenance expense due primarily to the cost of
    a forced outage at Rockport Plant Unit 2, a planned outage at Tanner's Creek
    Plant Unit 1 and storm damage expenses in May and June of 2004.
 o  A $3 million increase in Taxes Other Than Income Taxes primarily due to
    favorable property tax adjustments that were recorded in 2003.
 o  A $9 million increase in Income Taxes. See Income Taxes section below for
    further discussion.

Other Impacts on Earnings
-------------------------

Nonoperating Income increased $4 million due to favorable results from risk
management activities and increased barging revenues from nonaffiliated
companies.

Nonoperating Expenses increased $2 million mainly due to increased expenses
related to increased barging revenues from nonaffiliated companies.

Nonoperating Income Taxes increased $2 million. See Income Taxes section below
for further discussion.

Interest Charges decreased $4 million primarily due to a reduction in
outstanding long-term debt and due to lower interest rates from refunding higher
cost debt.

Income Taxes
------------

The effective tax rates for the second quarter of 2004 and 2003 were 36.7% and
135.4%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The change in the effective tax rate is primarily due to
lower pre-tax income in 2003 offsetting the effect of flow-through and permanent
differences, and state income taxes.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income increased $22 million primarily due to:

 o  A $27 million increase in Electric Generation, Transmission and
    Distribution revenues due to an increase in residential and commercial sales
    reflecting warmer spring weather in 2004, an improvement in industrial
    sales reflecting an improvement in the economy and the end of amortization
    of Cook Plant outage settlements.
 o  A $9 million decrease in Fuel for Electric Generation expense reflecting a
    change in fuel mix as nuclear generation increased 48% and coal-fired
    generation declined 18% due to generating unit availability.
 o  A $10 million decrease in Purchased Electricity from AEP Affiliates
    primarily due to a 10% increase in net generation.
 o  A decrease of $4 million in Other Operation expense which included the end
    of amortization of Cook Plant outage settlements.

The increase in Operating Income was partially offset by:

 o  A $7 million decrease in Sales to AEP Affiliates due to lower capacity
    revenues.
 o  A $10 million increase in Maintenance expense due primarily to both planned
    and forced outages at Rockport Plant Unit 2, a planned outage at Tanner's
    Creek Plant Unit 1 and increased cost of storm damage in May and June of
    2004.
 o  A $2 million increase in Taxes Other Than Income Taxes primarily due to
    favorable property tax adjustments recorded in 2003 offset by decreased
    Federal Insurance Contributions Act tax reflecting a reduction in employees
    from the sustained earnings improvement initiative and timing of payroll
    accrual.
 o  A $13 million increase in Income Taxes. See Income Taxes section below for
    further discussion.

Other Impacts on Earnings
-------------------------

Nonoperating Income increased $19 million primarily due to favorable results
from risk management activities.

Nonoperating Income Tax increased $8 million. See Income Taxes section below for
further discussion.

Interest Charges decreased $9 million primarily due to a reduction in
outstanding long-term debt and due to lower interest rates from refunding higher
cost debt.

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were 37.3% and
41.8%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The decrease in the effective tax rate is primarily due to
lower pre-tax income in 2003 offsetting the effect of flow-through and permanent
differences, and state income taxes.

Cumulative Effect of Accounting Change
--------------------------------------

The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 related to mark-to-market accounting for risk
management contracts that are not derivatives.

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

Cash Flow
---------

Cash flows for the first six months of 2004 and 2003 were as follows:

<TABLE>
<CAPTION>

                                                                             2004             2003
                                                                             ----             ----
                                                                                (in thousands)
                                                                          ---------        --------
<C>                                                                       <C>              <C>
   Cash and cash equivalents at beginning of period                         $3,899          $3,251
                                                                          ---------        --------
   Cash flow from (used for):
     Operating activities                                                  260,645          88,838
     Investing activities                                                  (78,054)        (70,850)
     Financing activities                                                 (183,319)        (15,513)
                                                                          ---------        --------
   Net increase (decrease) in cash and cash equivalents                       (728)          2,475
                                                                          ---------        --------
   Cash and cash equivalents at end of period                               $3,171          $5,726
                                                                          =========        ========
</TABLE>

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

Operating activities during 2004 provided $172 million more cash than during
2003 largely due to increased net income of $44 million and improved working
capital requirements.

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

Cash Flows Used For Investing Activities during 2004 were $7 million higher than
2003 primarily due to increased construction expenditures. Construction
expenditures for transmission and distribution assets were incurred to upgrade
or replace equipment and improve reliability.

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

Financing activities for 2004 used $168 million more cash from operations than
during 2003 primarily to reduce short-term debt outstanding and pay common
dividends.

Financing Activity
------------------

Long-term debt issuances and retirements during the first six months of 2004
were:

  Issuances
  ---------
    None.

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

   First Mortgage Bonds            $30,000             7.20             2024
   First Mortgage Bonds             25,000             7.50             2024


Off-Balance Sheet Arrangements
------------------------------

In prior years, we entered into off-balance sheet arrangements for various
reasons including accelerating cash collections, reducing operational expenses
and spreading risk of loss to third parties. Our off-balance sheet arrangement
has not changed significantly from year-end 2003 and is comprised of a sale and
leaseback transaction entered into by AEGCo and I&M with an unrelated
unconsolidated trustee. Our current policy restricts the use of off-balance
sheet financing entities or structures, except for traditional operating lease
arrangements and sales of customer accounts receivable that are entered into in
the normal course of business. For complete information on this off-balance
sheet arrangement see "Off-balance Sheet Arrangements" in "Management's
Financial Discussion and Analysis" section of our 2003 Annual Report.

Spent Nuclear Fuel Disposal
---------------------------

As a result of DOE's failure to make sufficient progress toward a permanent
repository or otherwise assume responsibility for spent nuclear fuel (SNF), we
and South Texas Project Nuclear Operating Company, along with a number of
unaffiliated utilities and states, filed suit in the D.C. Circuit Court
requesting, among other things, that the D.C. Circuit Court order DOE to meet
its obligations under the law. The D.C. Circuit Court ordered the parties to
proceed with contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, we filed a complaint in the U.S. Court of
Federal Claims seeking damages in excess of $150 million due to the DOE's
partial material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by
other utilities. In August 2000, in an appeal of related cases involving other
unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard contract between utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court. On January 17,
2003, the U.S. Court of Federal Claims ruled in our favor on the issue of
liability. The case continued on the issue of damages owed to us by the DOE. In
May 2004, the U.S. Court of Federal Claims ruled against us and denied damages,
which we intend to appeal. As long as the delay in the availability of the
government approved storage repository for SNF continues, the cost of both
temporary and permanent storage of SNF and the cost of decommissioning will
continue to increase. If such cost increases are not recovered on a timely basis
in regulated rates, future results of operations and cash flows could be
adversely affected.

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

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report 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
------------

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

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

                                        MTM Risk Management Contract Net Assets
                                            Six Months Ended June 30, 2004
                                                   (in thousands)

<C>                                                                                                       <C>
Total MTM Risk Management Contract Net Assets at December 31, 2003                                        $41,995
(Gain) Loss from Contracts Realized/Settled During the Period (a)                                         (13,076)
Fair Value of New Contracts When Entered Into During the Period (b)                                            -
Net Option Premiums Paid/(Received) (c)                                                                       404
Change in Fair Value Due to Valuation Methodology Changes                                                      -
Changes in Fair Value of Risk Management Contracts (d)                                                      1,913
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e)                    7,641
                                                                                                          --------
Total MTM Risk Management Contract Net Assets                                                              38,877
Net Cash Flow Hedge Contracts (f)                                                                          (4,394)
DETM Assignment (g)                                                                                       (18,276)
                                                                                                          --------
Total MTM Risk Management Contract Net Assets at June 30, 2004                                            $16,207
                                                                                                          ========

</TABLE>

(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
    includes realized risk management contracts and related derivatives
    that settled during 2004 that were entered into prior to 2004.
(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 2004. 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 2004.
(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.
(f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
    Accumulated Other Comprehensive Income (Loss).
(g) See Note 17 "Related Party Transactions" in the 2003 Annual Report.

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

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

<TABLE>
<CAPTION>

                                              Maturity and Source of Fair Value of MTM
                                                 Risk Management Contract Net Assets
                                            Fair Value of Contracts as of June 30, 2004

                                               Remainder                                                     After
                                                 2004          2005         2006       2007        2008       2008     Total (c)
                                               ---------       ----         ----       ----        ----      -----     ---------
                                                                                  (in thousands)
<C>                                            <C>            <C>         <C>         <C>        <C>        <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                              $(2,456)         $244         $(7)       $779         $-         $-     $(1,440)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                11,338         3,530       2,472       1,333        625          -      19,298
Prices Based on Models and Other
 Valuation Methods (b)                             150         3,994       1,856       3,260      3,310      8,449      21,019
                                               --------       -------     -------     -------    -------    -------    --------

Total                                           $9,032        $7,768      $4,321      $5,372     $3,935     $8,449     $38,877
                                               ========       =======     =======     =======    =======    =======    ========
</TABLE>

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



<PAGE>


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. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be market-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.

<TABLE>
<CAPTION>

                   Total Accumulated Other Comprehensive Income (Loss) Activity
                                 Six Months Ended June 30, 2004

                                                                            Interest
                                                              Power           Rate       Consolidated
                                                              -----         --------     ------------
                                                                         (in thousands)
<C>                                                         <C>                <C>          <C>
Beginning Balance December 31, 2003                            $222               $-           $222
Changes in Fair Value (a)                                    (1,968)            (351)        (2,319)
Reclassifications from AOCI to Net Income (b)                  (659)               -           (659)
                                                            --------           ------       --------
Ending Balance June 30, 2004                                $(2,405)           $(351)       $(2,756)
                                                            ========           ======       ========

</TABLE>

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

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,557 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

The following table shows the end, high, average, and low market risk as
measured by VaR the period indicated:

        Six Months Ended                          Twelve Months Ended
         June 30, 2004                             December 31, 2003
        ----------------                          -------------------
         (in thousands)                             (in thousands)

End     High     Average    Low              End     High   Average    Low
---     ----     -------    ---              ---     ----   -------    ---
$630   $1,430     $711     $357              $368   $1,429   $598     $142


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $88 million and $79 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
<PAGE>
<TABLE>
<CAPTION>


                                      INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                            CONSOLIDATED STATEMENTS OF OPERATIONS
                                 For the Three and Six Months Ended June 30, 2004 and 2003
                                                       (Unaudited)

                                                                           Three Months Ended              Six Months Ended
                                                                          --------------------          ---------------------
                                                                          2004            2003          2004             2003
                                                                          ----            ----          ----             ----
                                                                                           (in thousands)
<C>                                                                     <C>             <C>            <C>              <C>
                 OPERATING REVENUES
---------------------------------------------------
Electric Generation, Transmission and Distribution                      $339,874        $316,506       $693,272         $666,293
Sales to AEP Affiliates                                                   65,025          60,400        122,670          129,211
                                                                        ---------       ---------      ---------        ---------
TOTAL                                                                    404,899         376,906        815,942          795,504
                                                                        ---------       ---------      ---------        ---------

                 OPERATING EXPENSES
---------------------------------------------------
Fuel for Electric Generation                                              65,582          65,763        129,623          138,857
Purchased Electricity for Resale                                           6,191           7,035         12,554           13,317
Purchased Electricity from AEP Affiliates                                 65,665          73,353        128,793          139,251
Other Operation                                                          105,224         108,532        205,650          209,913
Maintenance                                                               46,276          42,595         84,318           73,962
Depreciation and Amortization                                             42,696          42,841         85,411           86,567
Taxes Other Than Income Taxes                                             15,472          12,149         30,688           28,970
Income Taxes                                                              14,798           5,409         39,097           26,448
                                                                        ---------       ---------      ---------        ---------
TOTAL                                                                    361,904         357,677        716,134          717,285
                                                                        ---------       ---------      ---------        ---------

OPERATING INCOME                                                          42,995          19,229         99,808           78,219

Nonoperating Income                                                       20,021          15,673         40,609           21,947
Nonoperating Expenses                                                     17,331          15,287         32,182           30,877
Nonoperating Income Tax Expense (Credit)                                     878            (849)         2,491           (5,300)
Interest Charges                                                          17,777          21,655         35,706           45,093
                                                                        ---------       ---------      ---------        ---------

Net Income (Loss) Before Cumulative Effect of Accounting Change           27,030          (1,191)        70,038           29,496
Cumulative Effect of Accounting Change (Net of Tax)                            -               -              -           (3,160)
                                                                        ---------       ---------      ---------        ---------

NET INCOME (LOSS)                                                         27,030          (1,191)        70,038           26,336

Preferred Stock Dividend Requirements (Including Capital
 Stock Expense)                                                              119           1,123            237            2,272
                                                                        ---------       ---------      ---------        ---------

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                               $26,911         $(2,314)       $69,801          $24,064
                                                                        =========       =========      =========        =========

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

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

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



                                             INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                      CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                    EQUITY AND COMPREHENSIVE INCOME
                                            For the Six Months Ended June 30, 2004 and 2003
                                                           (in thousands)
                                                             (Unaudited)


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

<C>                                                    <C>           <C>             <C>               <C>              <C>
DECEMBER 31, 2002                                      $56,584       $858,560        $143,996          $(40,487)        $1,018,653
Common Stock Dividends                                                                (20,000)                             (20,000)
Preferred Stock Dividends                                                              (2,205)                              (2,205)
Capital Stock Expense                                                      67             (67)                                   -
                                                                                                                        -----------
                                                                                                                           996,448
          COMPREHENSIVE INCOME
-----------------------------------------
Other Comprehensive Income (Loss),
  Net of Taxes:
   Cash Flow Hedges                                                                                      (1,276)            (1,276)
NET INCOME                                                                             26,336                               26,336
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                  25,060
                                                       --------      ---------       ---------         ---------        -----------
JUNE 30, 2003                                          $56,584       $858,627        $148,060          $(41,763)        $1,021,508
                                                       ========      =========       =========         =========        ===========

DECEMBER 31, 2003                                      $56,584       $858,694        $187,875          $(25,106)        $1,078,047
Common Stock Dividends                                                                (59,293)                             (59,293)
Preferred Stock Dividends                                                                (169)                                (169)
Capital Stock Expense                                                      67             (67)                                   -
                                                                                                                        -----------
                                                                                                                         1,018,585
          COMPREHENSIVE INCOME
-----------------------------------------
Other Comprehensive Income (Loss),
  Net of Taxes:
   Cash Flow Hedges                                                                                      (2,978)            (2,978)
NET INCOME                                                                             70,038                               70,038
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                  67,060
                                                       --------      ---------       ---------         ---------        -----------
JUNE 30, 2004                                          $56,584       $858,761        $198,384          $(28,084)        $1,085,645
                                                       ========      =========       =========         =========        ===========

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


                                        INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                  CONSOLIDATED BALANCE SHEETS
                                                           ASSETS
                                             June 30, 2004 and December 31, 2003
                                                         (Unaudited)

                                                                                                2004                   2003
                                                                                                ----                   ----
                                                                                                       (in thousands)
<C>                                                                                          <C>                    <C>
              ELECTRIC UTILITY PLANT
-----------------------------------------------------
Production                                                                                   $2,915,508             $2,878,051
Transmission                                                                                  1,003,939              1,000,926
Distribution                                                                                    969,804                958,966
General (including nuclear fuel)                                                                263,738                274,283
Construction Work in Progress                                                                   189,638                193,956
                                                                                             -----------            -----------
TOTAL                                                                                         5,342,627              5,306,182
Accumulated Depreciation and Amortization                                                     2,547,376              2,490,912
                                                                                             -----------            -----------
TOTAL - NET                                                                                   2,795,251              2,815,270
                                                                                             -----------            -----------

          OTHER PROPERTY AND INVESTMENTS
-----------------------------------------------------
Nuclear Decommissioning and Spent Nuclear Fuel
 Disposal Trust Funds                                                                         1,013,050                982,394
Non-Utility Property, Net                                                                        50,824                 52,303
Other Investments                                                                                31,608                 43,797
                                                                                             -----------            -----------
TOTAL                                                                                         1,095,482              1,078,494
                                                                                             -----------            -----------

                 CURRENT ASSETS
-----------------------------------------------------
Cash and Cash Equivalents                                                                         3,171                  3,899
Other Cash Deposits                                                                                  55                     15
Accounts Receivable:
  Customers                                                                                      56,158                 63,084
  Affiliated Companies                                                                           88,177                124,826
  Miscellaneous                                                                                   4,951                  4,498
  Allowance for Uncollectible Accounts                                                              (91)                  (531)
Fuel                                                                                             34,959                 33,968
Materials and Supplies                                                                          121,573                105,328
Risk Management Assets                                                                           61,545                 44,071
Margin Deposits                                                                                   2,728                  7,245
Prepayments and Other                                                                             9,694                 10,673
                                                                                             -----------            -----------
TOTAL                                                                                           382,920                397,076
                                                                                             -----------            -----------

          DEFERRED DEBITS AND OTHER ASSETS
-----------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Asset, Net                                                                143,986                151,973
  Incremental Nuclear Refueling Outage Expenses, Net                                             31,322                 57,326
  Other                                                                                          74,049                 66,978
Long-term Risk Management Assets                                                                 56,260                 43,768
Deferred Property Taxes                                                                          20,896                 21,916
Deferred Charges and Other Assets                                                                31,487                 26,270
                                                                                             -----------            -----------
TOTAL                                                                                           358,000                368,231
                                                                                             -----------            -----------

TOTAL ASSETS                                                                                 $4,631,653             $4,659,071
                                                                                             ===========            ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.

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



                                              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                        CONSOLIDATED BALANCE SHEETS
                                                      CAPITALIZATION AND LIABILITIES
                                                    June 30, 2004 and December 31, 2003
                                                               (Unaudited)

                                                                                                 2004                    2003
                                                                                                 ----                    ----
                                                                                                        (in thousands)
<C>                                                                                          <C>                     <C>
                     CAPITALIZATION
------------------------------------------------------------
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                                                                            858,761                 858,694
     Retained Earnings                                                                          198,384                 187,875
     Accumulated Other Comprehensive Income (Loss)                                              (28,084)                (25,106)
                                                                                             -----------             -----------
Total Common Shareholder's Equity                                                             1,085,645               1,078,047
Cumulative Preferred Stock - Not Subject to Mandatory Redemption                                  8,101                   8,101
                                                                                             -----------             -----------
Total Shareholder's Equity                                                                    1,093,746               1,086,148
Liability for Cumulative Preferred Stock - Subject to Mandatory
  Redemption                                                                                     61,445                  63,445
Long-term Debt                                                                                1,135,993               1,134,359
                                                                                             -----------             -----------
TOTAL                                                                                         2,291,184               2,283,952
                                                                                             -----------             -----------

                   CURRENT LIABILITIES
------------------------------------------------------------
Long-term Debt Due Within One Year                                                              150,000                 205,000
Advances from Affiliates                                                                         31,965                  98,822
Accounts Payable:
   General                                                                                       75,425                 101,776
   Affiliated Companies                                                                          41,730                  47,484
Customer Deposits                                                                                30,866                  21,955
Taxes Accrued                                                                                    86,512                  42,189
Interest Accrued                                                                                 16,986                  17,963
Risk Management Liabilities                                                                      56,297                  31,898
Obligations Under Capital Leases                                                                  6,053                   6,528
Other                                                                                            60,988                  57,675
                                                                                             -----------             -----------
TOTAL                                                                                           556,822                 631,290
                                                                                             -----------             -----------

           DEFERRED CREDITS AND OTHER LIABILITIES
------------------------------------------------------------
Deferred Income Taxes                                                                           326,660                 337,376
Regulatory Liabilities:
  Asset Removal Costs                                                                           269,921                 263,015
  Deferred Investment Tax Credits                                                                86,614                  90,278
  Excess ARO for Nuclear Decommissioning                                                        228,743                 215,715
  Other                                                                                          71,339                  61,268
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2                                      68,325                  70,179
Long-term Risk Management Liabilities                                                            45,301                  33,537
Obligations Under Capital Leases                                                                 29,262                  31,315
Asset Retirement Obligations                                                                    572,786                 553,219
Deferred Credits and Other                                                                       84,696                  87,927
                                                                                             -----------             -----------
TOTAL                                                                                         1,783,647               1,743,829
                                                                                             -----------             -----------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                         $4,631,653              $4,659,071
                                                                                             ===========             ===========

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


                                         INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                              CONSOLIDATED STATEMENTS OF CASH FLOWS
                                          For the Six Months Ended June 30 2004 and 2003
                                                           (Unaudited)

                                                                                               2004               2003
                                                                                               ----               ----
                                                                                                   (in thousands)
<C>                                                                                         <C>                 <C>
                OPERATING ACTIVITIES
--------------------------------------------------------
Net Income                                                                                   $70,038             $26,336
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
     Cumulative Effect of Accounting Change                                                        -               3,160
     Depreciation and Amortization                                                            85,411              86,567
     Deferred Income Taxes                                                                      (524)            (10,252)
     Deferred Investment Tax Credits                                                          (3,664)             (3,670)
     Deferred Property Taxes                                                                   1,211                 623
     Amortization (Deferral) of Incremental Nuclear
      Refueling Outage Expenses, Net                                                          26,004              (8,799)
     Unrecovered Fuel and Purchased Power Costs                                                1,171              18,751
     Amortization of Nuclear Outage Costs                                                          -              20,000
     Mark-to-Market of Risk Management Contracts                                               1,461              19,474
Changes in Certain Assets and Liabilities:
     Accounts Receivable, Net                                                                 42,682              73,530
     Fuel, Materials and Supplies                                                            (17,236)              1,599
     Accounts Payable                                                                        (32,105)           (107,218)
     Taxes Accrued                                                                            44,323             (19,201)
Change in Other Assets                                                                        12,014             (12,310)
Change in Other Liabilities                                                                   29,859                 248
                                                                                            ---------           ---------
Net Cash Flows From Operating Activities                                                     260,645              88,838
                                                                                            ---------           ---------

                INVESTING ACTIVITIES
--------------------------------------------------------
Construction Expenditures                                                                    (78,014)            (71,246)
Other                                                                                              -                 415
Change in Other Cash Deposits, Net                                                               (40)                (19)
                                                                                            ---------           ---------
Net Cash Flows Used For Investing Activities                                                 (78,054)            (70,850)
                                                                                            ---------           ---------

                FINANCING ACTIVITIES
--------------------------------------------------------
Retirement of Cumulative Preferred Stock                                                      (2,000)             (1,500)
Retirement of Long-term Debt - Nonaffiliated                                                 (55,000)           (255,000)
Change in Advances to/from Affiliates, Net                                                   (66,857)            263,192
Dividends Paid on Common Stock                                                               (59,293)            (20,000)
Dividends Paid on Cumulative Preferred Stock                                                    (169)             (2,205)
                                                                                            ---------           ---------
Net Cash Flows Used For Financing Activities                                                (183,319)            (15,513)
                                                                                            ---------           ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                            (728)              2,475
Cash and Cash Equivalents at Beginning of Period                                               3,899               3,251
                                                                                            ---------           ---------
Cash and Cash Equivalents at End of Period                                                    $3,171              $5,726
                                                                                            =========           =========

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $34,825,000 and $44,812,000 and for income taxes was $189,000 and $50,731,000
in 2004 and 2003, respectively.

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


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to I&M's consolidated financial statements are combined with the notes
to financial statements for other subsidiary registrants. Listed below are the
notes that apply to I&M. The footnotes begin on page L-1.

                                                                 Footnote
                                                                 Reference
                                                                 ---------

Significant Accounting Matters                                   Note 1

New Accounting Pronouncements                                    Note 2

Rate Matters                                                     Note 3

Customer Choice and Industry Restructuring                       Note 4

Commitments and Contingencies                                    Note 5

Guarantees                                                       Note 6

Benefit Plans                                                    Note 8

Business Segments                                                Note 9

Financing Activities                                             Note 10



<PAGE>










                             KENTUCKY POWER COMPANY



<PAGE>

                             KENTUCKY POWER COMPANY
            MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
            --------------------------------------------------------

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

Net Income for the second quarter of 2004 was relatively flat compared to the
prior year period as increased retail revenues were essentially offset by
increased Maintenance expenses.

Net Income for the six months ended June 30, 2004 was up $2 million over 2003
primarily due to favorable results on risk management activities, partially
offset by the Cumulative Effect of Accounting Change recorded in 2003.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income for the second quarter of 2004 was up slightly over the prior
year period. The positive factors contributing to the change in Operating Income
for 2004 were:

 o  A $10 million increase in Electric Generation, Transmission and Distribution
    revenues due to increased retail revenues due primarily to a weather
    related increase in residential and commercial sales, an improvement in
    industrial sales reflecting the recovering economy and the rate increase
    in mid-2003 to recover the cost of emission control equipment.
 o  A 32% increase in the Big Sandy Plant's generation which led to a decline
    in Purchases from AEP Affiliates of $4 million. The increase in generation
    was due to planned plant outages in 2003 for the implementation of emission
    control equipment.
 o  A $2 million decrease in Income Taxes (see "Income Taxes" below).

These increases in Operating Income were partially offset by:

 o  An increase in Fuel for Electric Generation expense of $10 million
    resulting from a 32% increase in generation over the second quarter of 2003
    and an increase in the average cost per ton of fuel consumed.
 o  An increase of $3 million in Maintenance expense related to planned outages
    for boiler overhauls in the second quarter of 2004 and storm damages in the
    second quarter of 2004.
 o  An increase in Depreciation and Amortization of $2 million in 2004 due to
    the implementation of emission control equipment at the Big Sandy plant in
    mid-2003.
 o  An increase in Other Operation expense of $1 million due to increased
    allocated costs from AEPSC.

Other Impacts on Earnings
-------------------------

Nonoperating Income (Loss) increased $1 million in the first quarter of 2004
compared to 2003 primarily due to favorable results from risk management
activities.

Interest Charges increased approximately $577 thousand primarily due to
increased long-term debt outstanding.

Income Taxes
------------

The effective tax rates for the second quarter of 2004 and 2003 were 21.7% and
30.6%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, amortization of investment tax credits and state income taxes. The
decrease in the effective tax rate is primarily due to lower state income taxes
offset by flow-through property-related differences.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income for 2004 was virtually unchanged from 2003. Items that
favorably impacted operating income were:

 o  A $13 million increase in Electric Generation, Transmission and Distribution
    revenues due to increased retail revenues primarily related to the rate
    increase in mid-2003 to recover the cost of emission control equipment.
 o  A decrease in Purchased Electricity from AEP Affiliates of $8 million
    resulting from a 30% increase in Big Sandy's generation in 2004. The
    increase in generation was due to planned plant outages in 2003 for the
    implementation of emission control equipment.
 o  A $2 million decrease in Income Taxes (see "Income Taxes" below).

These increases in Operating Income were partially offset by:

 o  An increase in Fuel for Electric Generation expense of $13 million resulting
    from a 30% increase in generation over 2003 and an increase in the average
    cost per ton of fuel consumed.
 o  An increase in Other Operation expense of $2 million due to increased
    allocated costs from AEPSC.
 o  An increase of $4 million in Maintenance expense related to planned outages
    for boiler overhauls in 2004.
 o  An increase in Depreciation and Amortization of $4 million in 2004 due to
    the implementation of emission control equipment at the Big Sandy plant in
    mid-2003.

Other Impacts on Earnings
-------------------------

Nonoperating Income (Loss) increased $5 million in 2004 compared to 2003
primarily due to favorable results from risk management activities.

Interest Charges increased $1 million primarily due to increased long-term debt
outstanding.

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were 32.2% and
35.1%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, amortization of investment tax credits and state income taxes. The
decrease in the effective tax rate is primarily due to lower state income taxes.

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

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

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

                                       Moody's       S&P         Fitch
                                       -------       ---         -----
    Senior Unsecured Debt              Baa2          BBB         BBB

Financing Activity
------------------

There were no long-term debt issuances or retirements during the first six
months of 2004.

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

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report 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
------------

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

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

                                   MTM Risk Management Contract Net Assets
                                      Six Months Ended June 30, 2004
                                             (in thousands)

<C>                                                                                                           <C>
Total MTM Risk Management Contract Net Assets at December 31, 2003                                            $15,490
(Gain) Loss from Contracts Realized/Settled During the Period (a)                                              (4,712)
Fair Value of New Contracts When Entered Into During the Period (b)                                                 -
Net Option Premiums Paid/(Received) (c)                                                                           142
Change in Fair Value Due to Valuation Methodology Changes                                                           -
Changes in Fair Value of Risk Management Contracts (d)                                                            406
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e)                        2,119
                                                                                                              --------
Total MTM Risk Management Contract Net Assets                                                                  13,445
Net Cash Flow Hedge Contracts (f)                                                                              (1,097)
DETM Assignment (g)                                                                                            (6,366)
                                                                                                              --------
Total MTM Risk Management Contract Net Assets at June 30, 2004                                                 $5,982
                                                                                                              ========

</TABLE>

(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
    includes realized risk management contracts and related derivatives
    that settled during 2004 that were entered into prior to 2004.
(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 2004. 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 2004.
(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.
(f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
    Accumulated Other Comprehensive Income (Loss).
(g) See Note 17 "Related Party Transactions" in the 2003 Annual Report.


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

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

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

<TABLE>
<CAPTION>

                                                 Maturity and Source of Fair Value of MTM
                                                   Risk Management Contract Net Assets
                                               Fair Value of Contracts as of June 30, 2004

                                          Remainder                                                        After
                                            2004            2005         2006        2007       2008       2008       Total (c)
                                          ---------         ----         ----        ----       ----       -----      ---------
                                                                                (in thousands)
<C>                                       <C>             <C>          <C>         <C>        <C>         <C>         <C>
Prices Actively Quoted - Exchange
 Traded Contracts                          $(855)            $85          $(2)       $271         $-          $-        $(501)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)           3,837           1,230          862         464        218           -        6,611
Prices Based on Models and Other
 Valuation Methods (b)                        67           1,391          646       1,135      1,153       2,943        7,335
                                          -------         -------      -------     -------    -------     -------     --------

Total                                     $3,049          $2,706       $1,506      $1,870     $1,371      $2,943      $13,445
                                          =======         =======      =======     =======    =======     =======     ========

</TABLE>

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


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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.

<TABLE>
<CAPTION>
                                 Total Accumulated Other Comprehensive Income (Loss) Activity
                                               Six Months Ended June 30, 2004

                                                             Power              Interest Rate           Consolidated
                                                             -----              -------------           ------------
                                                                                (in thousands)
<C>                                                          <C>                    <C>                    <C>
Beginning Balance December 31, 2003                            $82                  $338                    $420
Changes in Fair Value (a)                                     (693)                    -                    (693)
Reclassifications from AOCI to Net
 Income (b)                                                   (226)                  (43)                   (269)
                                                             ------                 -----                  ------
Ending Balance June 30, 2004                                 $(837)                 $295                   $(542)
                                                             ======                 =====                  ======
</TABLE>

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

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $450 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:

        Six Months Ended                          Twelve Months Ended
         June 30, 2004                             December 31, 2003
        ----------------                          -------------------
         (in thousands)                             (in thousands)

End     High     Average    Low              End     High   Average    Low
---     ----     -------    ---              ---     ----   -------    ---
$220    $498      $248     $124             $136     $527    $220      $52

VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $25 million and $29 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or financial position.
<PAGE>
<TABLE>
<CAPTION>


                                                           KENTUCKY POWER COMPANY
                                                            STATEMENTS OF INCOME
                                         For the Three and Six Months Ended June 30, 2004 and 2003
                                                                 (Unaudited)

                                                                        Three Months Ended                  Six Months Ended
                                                                       --------------------              ----------------------
                                                                       2004            2003              2004              2003
                                                                       ----            ----              ----              ----
                                                                                            (in thousands)
<C>                                                                  <C>              <C>               <C>              <C>
                 OPERATING REVENUES
--------------------------------------------------------
Electric Generation, Transmission and Distribution                   $94,034          $84,296           $200,935         $188,255
Sales to AEP Affiliates                                               12,373           11,168             18,985           19,303
                                                                     --------         --------          ---------        ---------
TOTAL                                                                106,407           95,464            219,920          207,558
                                                                     --------         --------          ---------        ---------

                 OPERATING EXPENSES
--------------------------------------------------------
Fuel for Electric Generation                                          25,224           15,439             46,118           33,386
Purchased Electricity from AEP Affiliates                             31,817           36,152             65,123           73,547
Other Operation                                                       13,153           11,695             26,280           23,832
Maintenance                                                           10,214            7,161             17,539           13,926
Depreciation and Amortization                                         10,905            9,248             21,764           17,960
Taxes Other Than Income Taxes                                          2,395            2,077              4,723            4,442
Income Taxes                                                           1,094            2,728              7,554            9,667
                                                                     --------         --------          ---------        ---------
TOTAL                                                                 94,802           84,500            189,101          176,760
                                                                     --------         --------          ---------        ---------

OPERATING INCOME                                                      11,605           10,964             30,819           30,798

Nonoperating Income (Loss)                                               674             (547)             1,626           (2,945)
Nonoperating Expenses                                                    466              113              1,779              362
Nonoperating Income Tax Expense (Credit)                                  33             (926)               (94)          (1,484)
Interest Charges                                                       7,712            7,135             15,081           13,859
                                                                     --------         --------          ---------        ---------

Income Before Cumulative Effect of Accounting Change                   4,068            4,095             15,679           15,116
Cumulative Effect of Accounting Change (Net of Tax)                        -                -                  -           (1,134)
                                                                     --------         --------          ---------        ---------

NET INCOME                                                            $4,068           $4,095            $15,679          $13,982
                                                                     ========         ========          =========        =========

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

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

<PAGE>
<TABLE>
<CAPTION>


                                                       KENTUCKY POWER COMPANY
                                            STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                  EQUITY AND COMPREHENSIVE INCOME
                                           For the Six Months Ended June 30, 2004 and 2003
                                                           (in thousands)
                                                             (Unaudited)


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

<C>                                                <C>           <C>              <C>                  <C>            <C>
DECEMBER 31, 2002                                  $50,450       $208,750         $48,269              $(9,451)       $298,018

Common Stock Dividends                                                            (10,966)                             (10,966)
                                                                                                                      ---------
TOTAL                                                                                                                  287,052
                                                                                                                      ---------

        COMPREHENSIVE INCOME
-------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Cash Flow Hedges                                                                                       (506)           (506)
NET INCOME                                                                         13,982                               13,982
                                                                                                                      ---------
TOTAL COMPREHENSIVE INCOME                                                                                              13,476
                                                   --------      ---------        --------             --------       ---------
JUNE 30, 2003                                      $50,450       $208,750         $51,285              $(9,957)       $300,528
                                                   ========      =========        ========             ========       =========

DECEMBER 31, 2003                                  $50,450       $208,750         $64,151              $(6,213)       $317,138

Common Stock Dividends                                                            (12,500)                             (12,500)
                                                                                                                      ---------
TOTAL                                                                                                                  304,638
                                                                                                                      ---------

        COMPREHENSIVE INCOME
-------------------------------------
Other Comprehensive Income (Loss),
  Net of Taxes:
   Cash Flow Hedges                                                                                       (962)           (962)
NET INCOME                                                                         15,679                               15,679
                                                                                                                      ---------
TOTAL COMPREHENSIVE INCOME                                                                                              14,717
                                                   --------      ---------        --------             --------       ---------
JUNE 30, 2004                                      $50,450       $208,750         $67,330              $(7,175)       $319,355
                                                   ========      =========        ========             ========       =========

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


                                                      KENTUCKY POWER COMPANY
                                                          BALANCE SHEETS
                                                              ASSETS
                                               June 30, 2004 and December 31, 2003
                                                           (Unaudited)

                                                                                                   2004                   2003
                                                                                                   ----                   ----
                                                                                                          (in thousands)
<C>                                                                                            <C>                    <C>
               ELECTRIC UTILITY PLANT
-------------------------------------------------
Production                                                                                       $460,577               $457,341
Transmission                                                                                      383,329                381,354
Distribution                                                                                      433,655                425,688
General                                                                                            59,248                 68,041
Construction Work in Progress                                                                      12,507                 17,322
                                                                                               -----------            -----------
TOTAL                                                                                           1,349,316              1,349,746
Accumulated Depreciation and Amortization                                                         385,237                381,876
                                                                                               -----------            -----------
TOTAL - NET                                                                                       964,079                967,870
                                                                                               -----------            -----------

            OTHER PROPERTY AND INVESTMENTS
-------------------------------------------------
Non-Utility Property, Net                                                                           5,442                  5,423
Other Investments                                                                                     398                  1,022
                                                                                               -----------            -----------
TOTAL                                                                                               5,840                  6,445
                                                                                               -----------            -----------

                   CURRENT ASSETS
-------------------------------------------------
Cash and Cash Equivalents                                                                             695                    863
Other Cash Deposits                                                                                    17                     23
Advances to Affiliates                                                                              3,522                      -
Accounts Receivable:
  Customers                                                                                        21,279                 21,177
  Affiliated Companies                                                                             21,631                 25,327
  Accrued Unbilled Revenues                                                                         4,501                  5,534
  Miscellaneous                                                                                       283                     97
  Allowance for Uncollectible Accounts                                                                (69)                  (736)
Fuel                                                                                               11,309                  9,481
Materials and Supplies                                                                             19,911                 16,585
Risk Management Assets                                                                             21,211                 16,200
Margin Deposits                                                                                       961                  2,660
Prepayments and Other                                                                               1,601                  1,696
                                                                                               -----------            -----------
TOTAL                                                                                             106,852                 98,907
                                                                                               -----------            -----------

          DEFERRED DEBITS AND OTHER ASSETS
-------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Asset, Net                                                                  102,853                 99,828
  Other Regulatory Assets                                                                          15,147                 13,971
Long-term Risk Management Assets                                                                   20,995                 16,134
Deferred Property Taxes                                                                             3,511                  6,847
Other Deferred Charges                                                                             11,515                 11,632
                                                                                               -----------            -----------
TOTAL                                                                                             154,021                148,412
                                                                                               -----------            -----------

TOTAL ASSETS                                                                                   $1,230,792             $1,221,634
                                                                                               ===========            ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                     KENTUCKY POWER COMPANY
                                                         BALANCE SHEETS
                                                 CAPATALIZATION AND LIABILITIES
                                              June 30, 2004 and December 31, 2003
                                                          (Unaudited)

                                                                                               2004                2003
                                                                                               ----                ----
                                                                                                   (in thousands)
<C>                                                                                        <C>                  <C>
                CAPITALIZATION
----------------------------------------------------
Common Shareholder's Equity:
  Common Stock - $50 Par Value:
    Authorized - 2,000,000 Shares
    Outstanding - 1,009,000 Shares                                                            $50,450              $50,450
    Paid-in Capital                                                                           208,750              208,750
    Retained Earnings                                                                          67,330               64,151
    Accumulated Other Comprehensive Income (Loss)                                              (7,175)              (6,213)
                                                                                           -----------          -----------
Total Common Shareholder's Equity                                                             319,355              317,138
                                                                                           -----------          -----------
Long-term Debt:
    Nonaffiliated                                                                             427,841              427,602
    Affiliated                                                                                 80,000               60,000
                                                                                           -----------          -----------
Total Long-term Debt                                                                          507,841              487,602
                                                                                           -----------          -----------
TOTAL                                                                                         827,196              804,740
                                                                                           -----------          -----------

               CURRENT LIABILITIES
----------------------------------------------------
Advances from Affiliates                                                                            -               38,096
Accounts Payable:
  General                                                                                      22,366               22,802
  Affiliated Companies                                                                         19,928               22,648
Customer Deposits                                                                              12,671                9,894
Taxes Accrued                                                                                  10,999                7,329
Interest Accrued                                                                                6,783                6,915
Risk Management Liabilities                                                                    20,613               11,704
Obligations Under Capital Leases                                                                1,653                1,743
Other                                                                                           7,979                8,628
                                                                                           -----------          -----------
TOTAL                                                                                         102,992              129,759
                                                                                           -----------          -----------

       DEFERRED CREDITS AND OTHER LIABILITIES
----------------------------------------------------
Deferred Income Taxes                                                                         219,244              212,121
Regulatory Liabilities:
  Asset Removal Costs                                                                          28,492               26,140
  Deferred Investment Tax Credits                                                               7,370                7,955
  Other Regulatory Liabilities                                                                 13,167               10,591
Long-term Risk Management Liabilities                                                          15,611               12,363
Obligations Under Capital Leases                                                                3,077                3,549
Deferred Credits and Other                                                                     13,643               14,416
                                                                                           -----------          -----------
TOTAL                                                                                         300,604              287,135
                                                                                           -----------          -----------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                       $1,230,792           $1,221,634
                                                                                           ===========          ===========

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


                                                        KENTUCKY POWER COMPANY
                                                       STATEMENTS OF CASH FLOWS
                                           For the Six Months Ended June 30, 2004 and 2003
                                                             (Unaudited)

                                                                                                    2004                2003
                                                                                                    ----                ----
                                                                                                         (in thousands)
<C>                                                                                               <C>                  <C>
                OPERATING ACTIVITIES
------------------------------------------------------
Net Income                                                                                        $15,679              $13,982
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Cumulative Effect of Accounting Change                                                               -                1,134
   Depreciation and Amortization                                                                   21,764               17,960
   Deferred Income Taxes                                                                            4,616                7,605
   Deferred Investment Tax Credits                                                                   (585)                (587)
   Deferred Property Taxes                                                                          3,424                3,150
   Deferred Fuel Costs, Net                                                                        (1,514)                (932)
   Loss on Sale of Assets                                                                           1,051                    -
   Mark-to-Market of Risk Management Contracts                                                      1,064                6,697
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                                         3,774               12,065
   Fuel, Materials and Supplies                                                                    (5,154)              (2,672)
   Accounts Payable                                                                                (3,156)             (43,251)
   Taxes Accrued                                                                                    3,670                6,175
Change in Other Assets                                                                             (4,165)              (4,773)
Change in Other Liabilities                                                                        10,013                1,261
                                                                                                  --------             --------
Net Cash Flows From Operating Activities                                                           50,481               17,814
                                                                                                  --------             --------

                 INVESTING ACTIVITIES
------------------------------------------------------
Construction Expenditures                                                                         (18,075)             (57,897)
Proceeds from Sales of Property and Other                                                           1,538                  298
Change in Other Cash Deposits, Net                                                                      6                   (1)
                                                                                                  --------             --------
Net Cash Flow Used for Investing Activities                                                       (16,531)             (57,600)
                                                                                                  --------             --------

                 FINANCING ACTIVITIES
------------------------------------------------------
Issuance of Long-term Debt - Affiliated                                                            20,000               74,263
Retirement of Long-term Debt - Nonaffiliated                                                            -              (40,000)
Retirement of Long-term Debt - Affiliated                                                               -              (15,000)
Change in Advances to/from Affiliates, Net                                                        (41,618)              30,876
Dividends Paid                                                                                    (12,500)             (10,966)
                                                                                                  --------             --------
Net Cash Flows From (Used For) Financing Activities                                               (34,118)              39,173
                                                                                                  --------             --------

Net Decrease in Cash and Cash Equivalents                                                            (168)                (613)
Cash and Cash Equivalents at Beginning of Period                                                      863                2,285
                                                                                                  --------             --------
Cash and Cash Equivalents at End of Period                                                           $695               $1,672
                                                                                                  ========             ========

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $14,625,000 and $13,245,000 and for income taxes was $658,000 and
$(5,537,000) in 2004 and 2003, respectively.

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



                             KENTUCKY POWER COMPANY
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to KPCo's financial statements are combined with the notes to
financial statements for other subsidiary registrants. Listed below are the
notes that apply to KPCo. The footnotes begin on page L-1.

                                                                Footnote
                                                                Reference
                                                                ---------

Significant Accounting Matters                                  Note 1

New Accounting Pronouncements                                   Note 2

Rate Matters                                                    Note 3

Commitments and Contingencies                                   Note 5

Guarantees                                                      Note 6

Benefit Plans                                                   Note 8

Business Segments                                               Note 9

Financing Activities                                            Note 10




<PAGE>










                         OHIO POWER COMPANY CONSOLIDATED



<PAGE>

                         OHIO POWER COMPANY CONSOLIDATED
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                 ----------------------------------------------

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

Effective July 1, 2003, we consolidated JMG Funding, LP (JMG) as a result of the
implementation of FIN 46. OPCo now records the depreciation, interest and other
operating expenses of JMG and eliminates JMG's revenues against OPCo's operating
lease expenses. While there was no effect to net income as a result of
consolidation, some individual income statement captions were affected.

Net Income decreased $17 million for the quarter due primarily to a $16 million
decrease in Sales to AEP Affiliates. Net Income decreased $130 million
year-to-date primarily due to a $125 million Cumulative Effect of Accounting
Changes in the first quarter of 2003. Income Before Cumulative Effect of
Accounting Changes decreased $6 million year-to-date primarily due to a decrease
in Sales to AEP affiliates.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income decreased $17 million for the three months ended June 30, 2004
compared with the three months ended June 30, 2003 due to:

 o  A $16 million decrease in Sales to AEP Affiliates. The decrease is primarily
    the result of a 29% decrease in MWH for affiliated system sales partially
    offset by an increase in price per MWH. The decrease in MWH was primarily
    a result of an increase in planned boiler overhauls.
 o  A $13 million decrease in non-affiliated wholesale energy sales due to lower
    sales volumes.
 o  A $10 million increase in Other Operation expense primarily due to a $7
    million pre-tax  adjustment in 2003 to the workers' compensation reserve
    related to the sale of coal companies coupled with an increase in allocated
    costs from AEPSC.
 o  A $10 million increase in Depreciation and Amortization expense primarily
    associated with the OPCo consolidation of JMG. Depreciation expense related
    to the assets owned by JMG are now consolidated with OPCo (there was no
    change in overall net income due to the consolidation of JMG). In addition,
    the increase is a result of a greater depreciable base in 2004, including
    capitalized software costs and the increased amortization of regulatory
    assets due to a federal tax adjustment which increased the regulatory asset
    amount and the corresponding amortization amount.

The decrease in Operating Income was partially offset by:

 o  A $10 million increase in retail electric revenues resulting from increased
    weather-related demand from residential and commercial customers and
    increased usage from industrial customers. Cooling degree days increased 59%
    for the three months ended June 30, 2004 compared to three months ended
    June 30, 2003.
 o  A $15 million increase due to favorable results from risk management
    activities.
 o  An $8 million decrease in Fuel for Electric Generation due to decreased net
    generation as a result of an increase in planned boiler overhauls.

Other Impacts of Earnings
-------------------------

Nonoperating Income increased $48 million primarily due to sales of excess
energy purchased from Dow at the Plaquemine, Louisiana plant (discussed in Note
5) including the effects of a related affiliate agreement which eliminates
OPCo's market exposure related to the purchases from Dow. There was no change in
overall Net Income due to the agreement with Dow.

Nonoperating Expense increased $42 million primarily due to the agreement to
purchase excess energy from Dow at the Plaquemine, Louisiana plant (discussed in
Note 5). There was no change in overall Net Income due to the agreement with
Dow.

Interest Charges increased $11 million due primarily to the consolidation of JMG
and its associated debt along with issuance of additional long-term debt
subsequent to second quarter 2003. (There was no change in overall Net Income
due to the consolidation of JMG).

Income Taxes
------------

The effective tax rates for the second quarter of 2004 and 2003 were 33.0% and
33.2%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The effective tax rates remained relatively flat for the
comparative period.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income decreased $7 million for the six months ended June 30, 2004
compared with the six months ended June 30, 2003 due to:

 o  A $20 million decrease in non-affiliated wholesale energy sales due to a
    lower sales volume.
 o  A $9 million decrease in Sales to AEP Affiliates.  The decrease is primarily
    the result of a 7.5% decrease in MWH for affiliated system sales.
 o  A $5 million increase in Fuel for Electric Generation due to higher pricing
    per MWH.
 o  A $7 million increase in Other Operation expense primarily due to a pre-tax
    adjustment in 2003 to the workers' compensation reserve related to the
    sale of coal companies.
 o  A $20 million increase in Depreciation and Amortization expense primarily
    associated with the OPCo consolidation of JMG. Depreciation expense related
    to the assets owned by JMG are consolidated with OPCo effective July 1,
    2003 (there was no change in overall Net Income due to the consolidation of
    JMG). In addition, the increase is a result of a greater depreciable base
    in 2004, including capitalized software and the increased amortization of
    regulatory assets due to a federal tax adjustment which increased the
    regulatory asset amount and the corresponding amortization amount.

The decrease in Operating Income was partially offset by:

 o  A $17 million increase in retail electric revenues resulting from increased
    weather-related demand from residential and commercial customers and
    increased usage from industrial customers. Cooling degree days increased 59%
    for the six months ended June 30, 2004 compared to the six months ended June
    30, 2003.
 o  A $9 million increase due to favorable results from risk management
    activities.
 o  An $11 million decrease in Purchased Electricity for Resale primarily due to
    cessation of the Buckeye Transmission agreement on June 30, 2003. Prior to
    this date, Ohio Edison interchange expenses were recorded in Purchased
    Electricity for Resale. An associated offsetting decrease in Ohio Edison
    revenue occurred in non affiliated sales for resale; therefore, there was no
    effect to net income. In addition, the DOE Settlement Capacity Surcharge
    related to Ohio Valley Electric surplus charges was included in rates
    through April 30, 2003, no longer in effect for 2004.
 o  A $23 million decrease in Income Taxes. See Income Taxes section below for
    further discussion.

Other Impacts of Earnings
-------------------------

Nonoperating Income increased $68 million primarily due to sales of excess
energy purchased from Dow at the Plaquemine, Louisiana plant (discussed in Note
5) including the effects of a related affiliate agreement which eliminates
OPCo's market exposure related to the purchases from Dow. There was no change in
overall Net Income due to the agreement with Dow. In addition, in the first six
months of 2004 results from risk management activities were favorable compared
to losses that were incurred in the first six months of 2003.

Nonoperating Expense increased $38 million primarily due to the agreement to
purchase excess energy from Dow at the Plaquemine, Louisiana plant (discussed in
Note 5). There was no change in overall Net Income due to the agreement with
Dow.

Interest Charges increased $23 million due primarily to the consolidation of JMG
and its associated debt along with issuance of additional long-term debt
subsequent to second quarter 2003. (There was no change in overall Net Income
due to the consolidation of JMG).

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were 35.0% and
39.7%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to the flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The decrease in the effective tax rate is primarily due to
lower state income taxes.

Cumulative Effect of Accounting Changes
---------------------------------------

The Cumulative Effect of Accounting Changes during 2003 was due to the one-time
after-tax impact of adopting SFAS 143 and implementing the requirements of EITF
02-3.

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

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

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

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

Cash Flow
---------

Cash flows for the six months ended June 30, 2004 and 2003 were as follows:

<TABLE>
<CAPTION>

                                                                       2004              2003
                                                                       ----              ----
                                                                           (in thousands)
<C>                                                                  <C>              <C>
Cash and cash equivalents at beginning of period                       $7,233           $5,275
                                                                     ---------        ---------
Cash flows from (used for):
  Operating activities                                                300,773           80,467
  Investing activities                                                (81,909)        (114,485)
  Financing activities                                               (219,703)          37,408
                                                                     ---------        ---------
Net increase (decrease) in cash and cash equivalents                     (839)           3,390
                                                                     ---------        ---------

Cash and cash equivalents at end of period                             $6,394           $8,665
                                                                     =========        =========

</TABLE>

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

Cash Flows From Operating Activities for the first six months of 2004 increased
$220 million compared to the first six months of 2003. This is primarily due to
significant reductions in Accounts Payable balances during the second quarter of
2003 partially associated with a wind-down of risk management activities in that
year.

Investing Activities
--------------------
Cash Flows Used For  Investing  Activities  decreased by $33 million during the
first six months of 2004  compared with the first six months of 2003 due
primarily to the Change in Other Cash Deposits, Net primarily as a result of
monies set aside in 2003 for the retirement of Installment Purchase Contracts
in 2004.

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

Cash Flows For Financing Activities used $220 million in the first six months of
2004 and provided $37 million in the first six months of 2003. This is primarily
due to a decrease in the change in Advances to/from Affiliates, Net, during the
first six months of 2004 as a result of becoming a net lender as opposed to a
net borrower.

Financing Activity
------------------

Long-term debt issuances and retirements during the first six months of 2004
were:

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

   Financing Obligations               $6,080            5.77          2024


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

   Installment Purchase Contracts     $50,000            6.85          2004
   Senior Unsecured Notes             140,000            7.375         2004
   Notes Payable                        1,500            6.27          2009
   Notes Payable                        2,927            6.81          2008
   First Mortgage Bonds                10,000            7.30          2024


Other
-----

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

AEP has agreements with Juniper Capital L.P. (Juniper) under which Juniper
constructed and financed a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and leased the Facility to AEP. AEP has
subleased the Facility to the Dow Chemical Company (Dow). The Facility is a
Dow-operated "qualifying cogeneration facility" for purposes of PURPA.
Commercial operation of the Facility as required by the agreements between
Juniper, AEP and Dow was achieved on March 18, 2004.

Dow uses a portion of the energy produced by the Facility and sells the excess
energy. OPCo has agreed to purchase up to approximately 800 MW of such excess
energy from Dow. Because the Facility is a major steam supply for Dow, Dow is
expected to operate the Facility at certain minimum levels, and OPCo is
obligated to purchase the energy generated at those minimum operating levels
(expected to be approximately 270 MW).

OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel
Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and
Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in
excess of market. OPCo has entered an agreement with an affiliate that
eliminates OPCo's market exposure related to the PPA. AEP has guaranteed this
affiliate's performance under the agreement. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant to
the PPA that TEM rejected as non-conforming. Commercial operation for purposes
of the PPA began April 2, 2004.

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

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

On March 26, 2004, OPCo requested that TEM provide assurances of performance of
its future obligations under the PPA, but TEM refused to do so. As indicated
above, OPCo also gave notice to TEM and declared April 2, 2004 as the
"Commercial Operations Date." Despite OPCo's prior tenders of replacement
electric power products to TEM beginning May 1, 2003 and despite OPCo's tender
of electric power products from the Facility to TEM beginning April 2, 2004, TEM
refused to accept and pay for them under the terms of the PPA. On April 5, 2004,
OPCo gave notice to TEM that OPCo (i) was suspending performance of its
obligations under PPA, (ii) would be seeking a declaration from the New York
federal court that the PPA has been terminated and (iii) would be pursuing
against TEM and Tractebel SA under the guaranty damages and the full termination
payment value of the PPA.

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

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report 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
------------

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

Roll-Forward of MTM Risk Management Contract Net Assets
-------------------------------------------------------

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

<TABLE>
<CAPTION>

                                      MTM Risk Management Contract Net Assets
                                         Six Months Ended June 30, 2004
                                                 (in thousands)

<C>                                                                                                                <C>
Total MTM Risk Management Contract Net Assets at December 31, 2003                                                 $53,938
(Gain) Loss from Contracts Realized/Settled During the Period (a)                                                  (18,460)
Fair Value of New Contracts When Entered Into During the Period (b)                                                      -
Net Option Premiums Paid/(Received) (c)                                                                                489
Change in Fair Value Due to Valuation Methodology Changes (d)                                                        1,189
Changes in Fair Value of Risk Management Contracts (e)                                                               9,965
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)                              -
                                                                                                                   --------
Total MTM Risk Management Contract Net Assets                                                                       47,121
Net Cash Flow Hedge Contracts (g)                                                                                   (4,615)
DETM Assignment (h)                                                                                                (22,057)
                                                                                                                   --------
Total MTM Risk Management Contracts Net Assets at June 30, 2004                                                    $20,449
                                                                                                                   ========

</TABLE>
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
   includes realized risk management contracts and related derivatives
   that settled during 2004 that were entered into prior to 2004.
(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 2004. 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 2004.
(d)"Change in Fair Value Due to Valuation Methodology Changes"
   represents the impact of AEP changes in methodology in regards to
   credit reserves on forward contracts.
(e)"Changes in Fair Value of Risk Management Contracts" represents the
   fair value change in the risk management portfolio due to market
   fluctuations during the current period. Market fluctuations are
   attributable to various factors such as supply/demand, weather,
   storage, etc.
(f)"Change in Fair Value of Risk Management Contracts Allocated to
   Regulated Jurisdictions" relates to the net gains (losses) of those
   contracts that are not reflected in the Consolidated Statements of
   Income. These net gains (losses) are recorded as regulatory
   liabilities/assets for those subsidiaries that operate in regulated
   jurisdictions.
(g)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
   Accumulated Other Comprehensive Income (Loss).
(h)See Note 17  "Related Party Transactions" in the 2003 Annual Report.


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

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

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



<TABLE>
<CAPTION>
                                                 Maturity and Source of Fair Value of MTM
                                                   Risk Management Contract Net Assets
                                               Fair Value of Contracts as of June 30, 2004

                                           Remainder                                                        After
                                             2004           2005        2006        2007         2008        2008      Total (c)
                                           ---------        ----        ----        ----         ----       -----      ---------
                                                                               (in thousands)
<C>                                        <C>           <C>          <C>         <C>           <C>        <C>         <C>
Prices Actively Quoted - Exchange
 Traded Contracts                          $(2,964)         $295         $(8)       $940            $-          $-     $(1,737)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)            13,047         5,244       2,985       1,608           755           -      23,639
Prices Based on Models and Other
 Valuation Methods (b)                         199         4,653       2,240       3,935         3,995      10,197      25,219
                                           --------      --------     -------     -------       -------    --------    --------

Total                                      $10,282       $10,192      $5,217      $6,483        $4,750     $10,197     $47,121
                                           ========      ========     =======     =======       =======    ========    ========
</TABLE>


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


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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, economic hedge contracts which are not
designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.

<TABLE>
<CAPTION>

          Total Accumulated Other Comprehensive Income (Loss) Activity
                         Six Months Ended June 30, 2004

                                                                    Foreign
                                                   Power            Currency         Consolidated
                                                   -----            --------         ------------
                                                                 (in thousands)
<C>                                               <C>                <C>              <C>
Beginning Balance December 31, 2003                  $268            $(371)             $(103)
Changes in Fair Value (a)                          (2,454)               -             (2,454)
Reclassifications from AOCI to Net
 Income (b)                                          (795)               7               (788)
                                                  --------           ------           --------
Ending Balance June 30, 2004                      $(2,981)           $(364)           $(3,345)
                                                  ========           ======           ========

</TABLE>


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

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,949 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:

        Six Months Ended                          Twelve Months Ended
         June 30, 2004                             December 31, 2003
        ----------------                          -------------------
         (in thousands)                             (in thousands)

End     High     Average    Low              End     High   Average    Low
---     ----     -------    ---              ---     ----   -------    ---
$761    $1,725     $858     $430            $444    $1,724   $722     $172


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $170 million and $214 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period; therefore, a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.


<PAGE>
<TABLE>
<CAPTION>


                                                   OHIO POWER COMPANY CONSOLIDATED
                                                 CONSOLIDATED STATEMENTS OF INCOME
                                     For the Three and Six Months Ended June 30, 2004 and 2003
                                                            (Unaudited)

                                                                              Three Months Ended              Six Months Ended
                                                                             --------------------           --------------------
                                                                             2004            2003           2004            2003
                                                                             ----            ----           ----            ----
                                                                                              (in thousands)
<C>                                                                        <C>             <C>            <C>             <C>
              OPERATING REVENUES
----------------------------------------------------
Electric Generation, Transmission and Distribution                         $397,645        $387,892        $840,863        $838,779
Sales to AEP Affiliates                                                     135,413         151,494         281,901         291,238
                                                                           ---------       ---------      ----------      ----------
TOTAL                                                                       533,058         539,386       1,122,764       1,130,017
                                                                           ---------       ---------      ----------      ----------

               OPERATING EXPENSES
----------------------------------------------------
Fuel for Electric Generation                                                145,503         153,446         311,774         307,094
Purchased Electricity for Resale                                             14,155          17,453          26,338          36,845
Purchased Electricity from AEP Affiliates                                    23,169          24,429          42,472          47,212
Other Operation                                                              94,334          84,641         184,919         177,622
Maintenance                                                                  56,733          53,411          90,784          88,868
Depreciation and Amortization                                                70,388          60,224         142,170         121,775
Taxes Other Than Income Taxes                                                43,646          39,613          90,836          86,768
Income Taxes                                                                 22,220          26,338          62,202          85,132
                                                                           ---------       ---------      ----------      ----------
TOTAL                                                                       470,148         459,555         951,495         951,316
                                                                           ---------       ---------      ----------      ----------

OPERATING INCOME                                                             62,910          79,831         171,269         178,701

Nonoperating Income                                                          52,882           4,823          69,812           2,099
Nonoperating Expenses                                                        49,231           7,331          57,300          19,041
Nonoperating Income Tax Expense (Credit)                                     (3,120)          1,564           1,967          (3,092)
Interest Charges                                                             30,898          19,482          62,867          40,224
                                                                           ---------       ---------      ----------      ----------

Income Before Cumulative Effect of Accounting Changes                        38,783          56,277         118,947         124,627
Cumulative Effect of Accounting Changes (Net of Tax)                              -               -               -         124,632
                                                                           ---------       ---------      ----------      ----------

NET INCOME                                                                   38,783          56,277         118,947         249,259

Preferred Stock Dividend Requirements                                           183             315             366             629
                                                                           ---------       ---------      ----------      ----------

EARNINGS APPLICABLE TO COMMON STOCK                                         $38,600         $55,962        $118,581        $248,630
                                                                           =========       =========      ==========      ==========

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

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


                                                    OHIO POWER COMPANY CONSOLIDATED
                                       CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                    EQUITY AND COMPREHENSIVE INCOME
                                            For the Six Months Ended June 30, 2004 and 2003
                                                            (in thousands)
                                                              (Unaudited)


                                                                                                   Accumulated Other
                                                       Common        Paid-in          Retained       Comprehensive
                                                       Stock         Capital          Earnings       Income (Loss)       Total
                                                       ------        -------          --------     -----------------     -----
<C>                                                    <C>           <C>              <C>              <C>            <C>
DECEMBER 31, 2002                                      $321,201      $462,483         $522,316         $(72,886)      $1,233,114

Common Stock Dividends                                                                 (83,867)                          (83,867)
Preferred Stock Dividends                                                                 (629)                             (629)
                                                                                                                      -----------
TOTAL                                                                                                                  1,148,618
                                                                                                                      -----------

       COMPREHENSIVE INCOME
------------------------------------
Other Comprehensive Income (Loss),
  Net of Taxes:
    Cash Flow Hedges                                                                                     (1,576)          (1,576)
    Minimum Pension Liability                                                                             5,624            5,624
NET INCOME                                                                             249,259                           249,259
                                                                                                                      -----------
TOTAL COMPREHENSIVE INCOME                                                                                               253,307
                                                       ---------     ---------        ---------        ---------      -----------
JUNE 30, 2003                                          $321,201      $462,483         $687,079         $(68,838)      $1,401,925
                                                       =========     =========        =========        =========      ===========

DECEMBER 31, 2003                                      $321,201      $462,484         $729,147         $(48,807)      $1,464,025

Common Stock Dividends                                                                (114,115)                         (114,115)
Preferred Stock Dividends                                                                 (366)                             (366)
                                                                                                                      -----------
TOTAL                                                                                                                  1,349,544
                                                                                                                      -----------

       COMPREHENSIVE INCOME
------------------------------------
Other Comprehensive Income (Loss),
  Net of Taxes:
    Cash Flow Hedges                                                                                     (3,242)          (3,242)
    Minimum Pension Liability                                                                            (3,942)          (3,942)
NET INCOME                                                                             118,947                           118,947
                                                                                                                      -----------
TOTAL COMPREHENSIVE INCOME                                                                                               111,763
                                                       ---------     ---------        ---------        ---------      -----------
JUNE 30, 2004                                          $321,201      $462,484         $733,613         $(55,991)      $1,461,307
                                                       =========     =========        =========        =========      ===========

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


                                                  OHIO POWER COMPANY CONSOLIDATED
                                                    CONSOLIDATED BALANCE SHEETS
                                                              ASSETS
                                               June 30, 2004 and December 31, 2003
                                                            (Unaudited)

                                                                                                   2004                    2003
                                                                                                   ----                    ----
                                                                                                           (in thousands)

<C>                                                                                             <C>                     <C>
                ELECTRIC UTILITY PLANT
-----------------------------------------------------
Production                                                                                      $4,077,693              $4,029,515
Transmission                                                                                       961,560                 938,805
Distribution                                                                                     1,178,394               1,156,886
General                                                                                            251,549                 245,434
Construction Work in Progress                                                                      158,402                 160,675
                                                                                                -----------             -----------
Total                                                                                            6,627,598               6,531,315
Accumulated Depreciation and Amortization                                                        2,548,729               2,485,947
                                                                                                -----------             -----------
TOTAL - NET                                                                                      4,078,869               4,045,368
                                                                                                -----------             -----------

             OTHER PROPERTY AND INVESTMENTS
-----------------------------------------------------
Non-Utility Property, Net                                                                           29,463                  29,291
Other                                                                                               20,215                  24,264
                                                                                                -----------             -----------
TOTAL                                                                                               49,678                  53,555
                                                                                                -----------             -----------

                     CURRENT ASSETS
-----------------------------------------------------
Cash and Cash Equivalents                                                                            6,394                   7,233
Other Cash Deposits                                                                                     65                  51,017
Advances to Affiliates                                                                             168,140                  67,918
Accounts Receivable:
   Customers                                                                                       109,095                 100,960
   Affiliated Companies                                                                            121,263                 120,532
   Accrued Unbilled Revenues                                                                         9,063                  17,221
   Miscellaneous                                                                                     1,198                     736
   Allowance for Uncollectible Accounts                                                               (343)                   (789)
Fuel                                                                                                90,009                  77,725
Materials and Supplies                                                                              98,955                  92,136
Risk Management Assets                                                                              78,637                  56,265
Margin Deposits                                                                                      3,849                   9,296
Prepayments and Other                                                                               13,025                  15,883
                                                                                                -----------             -----------
TOTAL                                                                                              699,350                 616,133
                                                                                                -----------             -----------

             DEFERRED DEBITS AND OTHER ASSETS
-----------------------------------------------------
Regulatory Assets:
   SFAS 109 Regulatory Asset, Net                                                                  170,684                 169,605
   Transition Regulatory Assets                                                                    267,673                 310,035
   Unamortized Loss on Reacquired Debt                                                              11,405                  10,172
   Other                                                                                            23,450                  22,506
Long-term Risk Management Assets                                                                    71,411                  52,825
Deferred Property Taxes                                                                             36,677                  67,469
Deferred Charges and Other Assets                                                                   38,112                  26,850
                                                                                                -----------             -----------
TOTAL                                                                                              619,412                 659,462
                                                                                                -----------             -----------

TOTAL ASSETS                                                                                    $5,447,309              $5,374,518
                                                                                                ===========             ===========

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


                                                    OHIO POWER COMPANY CONSOLIDATED
                                                      CONSOLIDATED BALANCE SHEETS
                                                     CAPITALIZATION AND LIABILITIES
                                                  June 30, 2004 and December 31, 2003
                                                              (Unaudited)

                                                                                                  2004                    2003
                                                                                                  ----                    ----
                                                                                                        (in thousands)
<C>                                                                                            <C>                     <C>
                   CAPITALIZATION
------------------------------------------------------------
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                 462,484
    Retained Earnings                                                                             733,613                 729,147
    Accumulated Other Comprehensive Income (Loss)                                                 (55,991)                (48,807)
                                                                                               -----------             -----------
Total Common Shareholder's Equity                                                               1,461,307               1,464,025
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                     16,644                  16,645
                                                                                               -----------             -----------
Total Shareholder's Equity                                                                      1,477,951               1,480,670
Liability for Cumulative Preferred Stock Subject to
 Mandatory Redemption                                                                               5,000                   7,250
Long-term Debt:
    Nonaffiliated                                                                               1,610,480               1,608,086
    Affiliated                                                                                    200,000                      -
                                                                                               -----------             -----------
Total Long-term Debt                                                                            1,810,480               1,608,086
                                                                                               -----------             -----------
TOTAL                                                                                           3,293,431               3,096,006
                                                                                               -----------             -----------

Minority Interest                                                                                  15,187                  16,314
                                                                                               -----------             -----------

                  CURRENT LIABILITIES
------------------------------------------------------------
Short-term Debt - General                                                                          21,539                  25,941
Long-term Debt Due Within One Year - Nonaffiliated                                                233,857                 431,854
Accounts Payable:
  General                                                                                         124,813                 104,874
  Affiliated Companies                                                                             83,459                 101,758
Customer Deposits                                                                                  28,099                  17,308
Taxes Accrued                                                                                     153,485                 132,793
Interest Accrued                                                                                   45,320                  45,679
Risk Management Liabilities                                                                        72,462                  38,318
Obligations Under Capital Leases                                                                    8,847                   9,624
Other                                                                                              66,525                  71,642
                                                                                               -----------             -----------
TOTAL                                                                                             838,406                 979,791
                                                                                               -----------             -----------

         DEFERRED CREDITS AND OTHER LIABILITIES
------------------------------------------------------------
Deferred Income Taxes                                                                             935,192                 933,582
Regulatory Liabilities:
  Asset Removal Costs                                                                             104,409                 101,160
  Deferred Investment Tax Credits                                                                  14,118                  15,641
  Other                                                                                                 -                       3
Long-term Risk Management Liabilities                                                              57,137                  40,477
Deferred Credits                                                                                   24,459                  23,222
Obligations Under Capital Leases                                                                   21,826                  25,064
Asset Retirement Obligations                                                                       44,338                  42,656
Other                                                                                              98,806                 100,602
                                                                                               -----------             -----------
TOTAL                                                                                           1,300,285               1,282,407
                                                                                               -----------             -----------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                           $5,447,309              $5,374,518
                                                                                               ===========             ===========

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

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



                                                  OHIO POWER COMPANY CONSOLIDATED
                                               CONSOLIDATED STATEMENTS OF CASH FLOWS
                                          For the Six Months Ended June 30, 2004 and 2003
                                                            (Unaudited)

                                                                                                         2004              2003
                                                                                                         ----              ----
                                                                                                             (in thousands)
<C>                                                                                                    <C>               <C>
                 OPERATING ACTIVITIES
-------------------------------------------------------
Net Income                                                                                             $118,947          $249,259
Adjustments to Reconcile Net Income to Net Cash Flows
   From Operating Activities:
      Cumulative Effect of Accounting Changes                                                                 -          (124,632)
      Depreciation and Amortization                                                                     142,170           121,775
      Deferred Income Taxes                                                                               4,400               372
      Deferred Investment Tax Credits                                                                    (1,523)           (1,525)
      Deferred Property Taxes                                                                            31,099            29,337
      Mark-to-Market of Risk Management Contracts                                                         4,819            26,381
Changes in Certain Assets and Liabilities:
      Accounts Receivable, Net                                                                           (1,616)            4,259
      Fuel, Materials and Supplies                                                                      (19,103)           (2,519)
      Prepayments and Other                                                                               8,305           (20,542)
      Accounts Payable                                                                                    1,640          (153,474)
      Customer Deposits                                                                                  10,791             9,524
      Taxes Accrued                                                                                      20,692            16,297
      Interest Accrued                                                                                     (359)           10,105
Change in Other Assets                                                                                  (11,397)          (42,716)
Change in Other Liabilities                                                                              (8,092)          (41,434)
                                                                                                       ---------         ---------
Net Cash Flows From Operating Activities                                                                300,773            80,467
                                                                                                       ---------         ---------

                 INVESTING ACTIVITIES
-------------------------------------------------------
Construction Expenditures                                                                              (134,001)         (117,761)
Change in Other Cash Deposits, Net                                                                       50,952                 -
Proceeds from Sale of Property and Other                                                                  1,140             3,276
                                                                                                       ---------         ---------
Net Cash Flows Used For Investing Activities                                                            (81,909)         (114,485)
                                                                                                       ---------         ---------

                 FINANCING ACTIVITIES
-------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated                                                                6,080           494,375
Issuance of Long-term Debt - Affiliated                                                                 200,000                 -
Change in Advances to/from Affiliates, Net                                                             (100,222)          232,881
Change in Short-term Debt, Net                                                                           (4,402)                -
Change in Short-term Debt - Affiliates, Net                                                                   -          (275,000)
Retirement of Long-term Debt - Nonaffiliated                                                           (204,427)          (29,850)
Retirement of Long-term Debt - Affiliated                                                                     -          (300,000)
Retirement of Cumulative Preferred Stock                                                                 (2,251)             (502)
Dividends Paid on Common Stock                                                                         (114,115)          (83,867)
Dividends Paid on Cumulative Preferred Stock                                                               (366)             (629)
                                                                                                       ---------         ---------
Net Cash Flows (Used For) From Financing Activities                                                    (219,703)           37,408
                                                                                                       ---------         ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                                       (839)            3,390
Cash and Cash Equivalents at Beginning of Period                                                          7,233             5,275
                                                                                                       ---------         ---------
Cash and Cash Equivalents at End of Period                                                               $6,394            $8,665
                                                                                                       =========         =========


SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $60,282,000 and $29,304,000 and for income taxes was $(8,420,000)
and $26,455,000 in 2004 and 2003, respectively.

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




                         OHIO POWER COMPANY CONSOLIDATED
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to OPCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below
are the notes that apply to OPCo. The footnotes begin on page L-1.

                                                             Footnote
                                                             Reference
                                                             ---------

Significant Accounting Matters                               Note 1

New Accounting Pronouncements                                Note 2

Rate Matters                                                 Note 3

Customer Choice and Industry Restructuring                   Note 4

Commitments and Contingencies                                Note 5

Guarantees                                                   Note 6

Benefit Plans                                                Note 8

Business Segments                                            Note 9

Financing Activities                                         Note 10



<PAGE>










                       PUBLIC SERVICE COMPANY OF OKLAHOMA



<PAGE>

                       PUBLIC SERVICE COMPANY OF OKLAHOMA
            MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
            --------------------------------------------------------

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

Net Income decreased $20 million for 2004 year-to-date, and $11 million for the
second quarter due mainly to increased expenses for power plant maintenance,
tree trimming, line clearance and storm damage repairs.

Fluctuations occurring in the retail portion of fuel and purchased power expense
generally do not impact operating income, as they are offset in revenues due to
the functioning of the fuel adjustment clause in Oklahoma.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income decreased $12 million primarily due to:

 o  Decreased retained margins of $2 million due mainly to decreased realization
    of off-system sales.
 o  Decreased transmission revenues of $2 million due mainly to non-affiliated
    transactions.
 o  Increased Other Operation expenses of $5 million primarily related to
    affiliated ancillary services, general transmission and distribution related
    expenses.
 o  Increased Maintenance expense of $11 million due mainly to increased power
    plant maintenance and tree trimming, along with increased repairs due to
    storm damage.
 o  Increased Taxes Other Than Income Taxes of $1 million due primarily to
    higher  property  and  unemployment  related  taxes,  offset in part by
    lower state franchise taxes.

The decrease in Operating Income was partially offset by:

 o  Increased retail base revenue of $8 million (5%), resulting mainly from
    increased KWH sales of 8%.  Heating and cooling degree-days increased 12%.

Other Impacts on Earnings
-------------------------

Interest Charges decreased $2 million due to reduced interest rates from
refinancing higher cost debt.

Income Taxes
------------

The effective tax rates for the second quarter of 2004 and 2003 were 21.0% and
18.2%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The increase in the effective tax
rate is primarily due to higher state income taxes offset by lower pre-tax
income in 2004.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income decreased $24 million primarily due to:

 o  Decreased retained margins of $4 million due mainly to decreased realization
    of off-system sales.
 o  Decreased transmission revenues of $3 million due mainly to non-affiliated
    transactions.
 o  Increased Other Operation expenses of $17 million, of which $9 million was
    transmission expense primarily related to a prior year true up for OATT
    transmission recorded in 2004 resulting from revised data from ERCOT for the
    years 2001-2003. Increased distribution expenses of $5 million resulting
    mainly from a labor settlement and various inventory and tracking system
    upgrades. Increased administrative and general expenses resulted from
    outside services and employee related expenses.
 o  Increased  Maintenance expense of $14 million due mainly to increased power
    plant maintenance and tree trimming along with increased repairs due to
    storm damage.
The decrease in Operating Income was partially offset by:

 o  Increased retail base revenue of $9 million (5%), resulting mainly from
    increased KWH sales of 3%. Total heating and cooling degree-days decreased
    9%, but overall customer usage not related to weather increased, as did the
    number of customers.

Other Impacts on Earnings
-------------------------

Interest Charges decreased $5 million due to reduced interest rates from
refinancing higher cost debt.

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were 78.1% and
15.3%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The increase in the effective tax
rate is primarily due to pre-tax income becoming a loss in 2004 and state income
taxes.

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

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

The rating agencies currently have us on stable outlook. Our first mortgage
bonds were upgraded by S&P to A- due to a change in methodology at the agency.
Current ratings are as follows:

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

Financing Activity
------------------

Long-term debt issuances and retirements during the first six months of 2004
were:

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

 Installment Purchase Contracts         $33,700          Variable        2014
 Senior Unsecured Notes                  50,000            4.70          2009

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

 Notes Payable to Trust                 $77,320            8.00          2037
 Installment Purchase Contracts          33,700            4.875         2014

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

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report 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.



<PAGE>


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

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

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

                                       MTM Risk Management Contract Net Assets
                                            Six Months Ended June 30, 2004
                                                    (in thousands)

<C>                                                                                                              <C>
Total MTM Risk Management Contract Net Assets at December 31, 2003                                               $14,057
(Gain) Loss from Contracts Realized/Settled During the Period (a)                                                   (973)
Fair Value of New Contracts When Entered Into During the Period (b)                                                    -
Net Option Premiums Paid/(Received) (c)                                                                               62
Change in Fair Value Due to Valuation Methodology Changes                                                              -
Changes in Fair Value of Risk Management Contracts (d)                                                                 -
Changes in Fair Value of Risk Management  Contracts Allocated to Regulated Jurisdictions (e)                      (9,327)
                                                                                                                 --------
Total MTM Risk Management Contract Net Assets                                                                      3,819
Net Cash Flow Hedge Contracts (f)                                                                                   (567)
                                                                                                                 --------
Total MTM Risk Management Contract Net Assets at June 30, 2004                                                    $3,252
                                                                                                                 ========
</TABLE>

(a) "(Gain) Loss from Contracts Realized/Settled During the Period" includes
    realized risk management contracts and related derivatives that settled
    during 2004 that were entered into prior to 2004.
(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 2004. 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 2004.
(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 Statements of Operations. These
    net gains (losses) are recorded as regulatory liabilities/assets for
    those subsidiaries that operate in regulated jurisdictions.
(f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
    Accumulated Other Comprehensive Income (Loss).

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

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

<TABLE>
<CAPTION>

                                                    Maturity and Source of Fair Value of MTM
                                                       Risk Management Contract Net Assets
                                                   Fair Value of Contracts as of June 30, 2004

                                            Remainder                                                           After
                                               2004           2005          2006        2007         2008       2008      Total (c)
                                            ---------         ----          ----        ----         ----       ----      ---------
                                                                                   (in thousands)
<C>                                            <C>           <C>            <C>         <C>         <C>         <C>       <C>
 Prices Actively Quoted -
  Exchange Traded Contracts                    $(379)           $38          $(1)       $120          $-          $-       $(222)
 Prices Provided by Other External
  Sources - OTC Broker Quotes (a)              1,468            795          158           -           -           -       2,421
 Prices Based on Models and Other
  Valuation Methods (b)                          (90)           618          (45)        119         256         762       1,620
                                               ------        -------        -----       -----       -----       -----     -------

 Total                                          $999         $1,451         $112        $239        $256        $762      $3,819
                                               ======        =======        =====       =====       =====       =====     =======
</TABLE>

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


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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, economic hedge contracts which are not
designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.

          Total Accumulated Other Comprehensive Income (Loss) Activity
                         Six Months Ended June 30, 2004
                                                                    Power
                                                                    -----
                                                               (in thousands)
    Beginning Balance December 31, 2003                             $156
    Changes in Fair Value (a)                                       (426)
    Reclassifications from AOCI to Net Income (b)                   (100)
                                                                   ------
    Ending Balance June 30, 2004                                   $(370)
                                                                   ======

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

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $236 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

VaR Associated with Risk Management Contracts
---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:

        Six Months Ended                          Twelve Months Ended
         June 30, 2004                             December 31, 2003
        ----------------                          -------------------
         (in thousands)                             (in thousands)

End     High     Average    Low              End     High   Average    Low
---     ----     -------    ---              ---     ----   -------    ---
$97     $221      $110      $55             $258    $1,004   $420     $100


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $45 million and $66 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or financial position.


<PAGE>
<TABLE>
<CAPTION>


                                                 PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                      STATEMENTS OF OPERATIONS
                                      For the Three and Six Months Ended June 30, 2004 and 2003
                                                             (Unaudited)

                                                                          Three Months Ended                Six Months Ended
                                                                         --------------------             --------------------
                                                                         2004            2003             2004            2003
                                                                         ----            ----             ----            ----
                                                                                            (in thousands)
<C>                                                                   <C>              <C>              <C>             <C>
                  OPERATING REVENUES
------------------------------------------------------
Electric Generation, Transmission and Distribution                    $228,653         $267,213         $432,696        $505,480
Sales to AEP Affiliates                                                  2,954           10,023            6,096          14,418
                                                                      ---------        ---------        ---------       ---------
TOTAL                                                                  231,607          277,236          438,792         519,898
                                                                      ---------        ---------        ---------       ---------

                  OPERATING EXPENSES
------------------------------------------------------
Fuel for Electric Generation                                            87,006          135,395          176,091         238,569
Purchased Electricity for Resale                                         5,583            6,863           14,751          19,354
Purchased Electricity from AEP Affiliates                               28,200           28,276           55,099          70,383
Other Operation                                                         36,768           31,684           80,163          63,302
Maintenance                                                             22,875           12,366           35,997          21,760
Depreciation and Amortization                                           22,159           21,359           44,335          42,853
Taxes Other Than Income Taxes                                            9,727            8,439           19,544          18,085
Income Taxes (Credits)                                                   2,429            4,139           (4,904)          3,731
                                                                      ---------        ---------        ---------       ---------
TOTAL                                                                  214,747          248,521          421,076         478,037
                                                                      ---------        ---------        ---------       ---------

OPERATING INCOME                                                        16,860           28,715           17,716          41,861

Nonoperating Income                                                        127               72              371             722
Nonoperating Expense (Credit)                                              762             (276)           1,304             163
Nonoperating Income Tax (Credit)                                          (467)            (155)            (859)           (355)
Interest Charges                                                         9,301           11,291           19,254          24,157
                                                                      ---------        ---------        ---------       ---------

NET INCOME (LOSS)                                                        7,391           17,927           (1,612)         18,618

Preferred Stock Dividend Requirements                                       53               53              106             106
                                                                      ---------        ---------        ---------       ---------

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                              $7,338          $17,874          $(1,718)        $18,512
                                                                      =========        =========        =========       =========

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

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


                                                PUBLIC SERVICE COMPANY OF OKLAHOMA
                                          STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                 EQUITY AND COMPREHENSIVE INCOME
                                        For the Six Months Ended June 30, 2004 and 2003
                                                         (in thousands)
                                                           (Unaudited)


                                                                                                     Accumulated Other
                                                      Common         Paid-in         Retained          Comprehensive
                                                      Stock          Capital         Earnings          Income (Loss)      Total
                                                      ------         -------         --------        -----------------    -----
<C>                                                   <C>            <C>              <C>                <C>             <C>
DECEMBER 31, 2002                                     $157,230       $180,016         $116,474           $(54,473)       $399,247

Capital Contribution from Parent                                       50,000                                              50,000
Common Stock Dividends                                                                  (7,500)                            (7,500)
Preferred Stock Dividends                                                                 (106)                              (106)
Distribution of Investment in AEMT, Inc.
  Preferred Shares to Parent                                                              (548)                              (548)
                                                                                                                         ---------
TOTAL                                                                                                                     441,093
                                                                                                                         ---------

         COMPREHENSIVE INCOME
-----------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Cash Flow Hedges                                                                                          (879)           (879)
   Minimum Pension Liability                                                                                  (58)            (58)
NET INCOME                                                                              18,618                             18,618
                                                                                                                         ---------
TOTAL COMPREHENSIVE INCOME                                                                                                 17,681
                                                      ---------      ---------        ---------          ---------       ---------
JUNE 30, 2003                                         $157,230       $230,016         $126,938           $(55,410)       $458,774
                                                      =========      =========        =========          =========       =========


DECEMBER 31, 2003                                     $157,230       $230,016         $139,604           $(43,842)       $483,008

Gain on Reacquired Preferred Stock                                                           2                                  2
Common Stock Dividends                                                                 (17,500)                           (17,500)
Preferred Stock Dividends                                                                 (106)                              (106)
                                                                                                                         ---------
TOTAL                                                                                                                     465,404
                                                                                                                         ---------

      COMPREHENSIVE INCOME (LOSS)
-----------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Cash Flow Hedges                                                                                          (526)           (526)
NET LOSS                                                                                (1,612)                            (1,612)
                                                                                                                         ---------
TOTAL COMPREHENSIVE INCOME (LOSS)                                                                                          (2,138)
                                                      ---------      ---------        ---------          ---------       ---------
JUNE 30, 2004                                         $157,230       $230,016         $120,388           $(44,368)       $463,266
                                                      =========      =========        =========          =========       =========

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



<PAGE>
<TABLE>
<CAPTION>


                                                      PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                                BALANCE SHEETS
                                                                   ASSETS
                                                     June 30, 2004 and December 31, 2003
                                                                (Unaudited)

                                                                                               2004                   2003
                                                                                               ----                   ----
                                                                                                       (in thousands)

<C>                                                                                         <C>                     <C>
               ELECTRIC UTILITY PLANT
------------------------------------------------
Production                                                                                 $1,068,770              $1,065,408
Transmission                                                                                  453,936                 451,292
Distribution                                                                                1,061,487               1,031,229
General                                                                                       208,736                 203,756
Construction Work in Progress                                                                  41,446                  54,711
                                                                                           -----------             -----------
TOTAL                                                                                       2,834,375               2,806,396
Accumulated Depreciation and Amortization                                                   1,097,590               1,069,216
                                                                                           -----------             -----------
TOTAL - NET                                                                                 1,736,785               1,737,180
                                                                                           -----------             -----------

            OTHER PROPERTY AND INVESTMENTS
------------------------------------------------
Non-Utility Property, Net                                                                       4,411                   4,631
Other Investments                                                                                   -                   2,320
                                                                                           -----------             -----------
TOTAL                                                                                           4,411                   6,951
                                                                                           -----------             -----------

                   CURRENT ASSETS
------------------------------------------------
Cash and Cash Equivalents                                                                       3,843                   3,738
Other Cash Deposits                                                                             6,954                  10,520
Accounts Receivable:
  Customers                                                                                    29,892                  28,515
  Affiliated Companies                                                                         20,889                  19,852
  Miscellaneous                                                                                 3,017                       -
  Allowance for Uncollectible Accounts                                                            (27)                    (37)
Fuel Inventory                                                                                 21,083                  18,331
Materials and Supplies                                                                         38,930                  38,125
Regulatory Asset for Under-recovered Fuel Costs                                                36,853                  24,170
Risk Management Assets                                                                          6,632                  18,586
Margin Deposits                                                                                   374                   4,351
Prepayments and Other                                                                           2,700                   2,655
                                                                                           -----------             -----------
TOTAL                                                                                         171,140                 168,806
                                                                                           -----------             -----------

          DEFERRED DEBITS AND OTHER ASSETS
------------------------------------------------
Regulatory Assets:
  Unamortized Loss on Reacquired Debt                                                          15,517                  14,357
  Other                                                                                        12,351                  14,342
Long-term Risk Management Assets                                                                3,831                  10,379
Deferred Charges                                                                               35,239                  18,017
                                                                                           -----------             -----------
TOTAL                                                                                          66,938                  57,095
                                                                                           -----------             -----------

TOTAL ASSETS                                                                               $1,979,274              $1,970,032
                                                                                           ===========             ===========

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


                                                 PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                            BALANCE SHEETS
                                                   CAPITALIZATION AND LIABILITIES
                                                 June 30, 2004 and December 31, 2003
                                                             (Unaudited)

                                                                                                   2004                   2003
                                                                                                   ----                   ----
                                                                                                          (in thousands)

<C>                                                                                           <C>                     <C>
                      CAPITALIZATION
--------------------------------------------------------------
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                 230,016
    Retained Earnings                                                                            120,388                 139,604
    Accumulated Other Comprehensive Income (Loss)                                                (44,368)                (43,842)
                                                                                              -----------             -----------
Total Common Shareholder's Equity                                                                463,266                 483,008
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                     5,262                   5,267
                                                                                              -----------             -----------
Total Shareholder's Equity                                                                       468,528                 488,275
Long-term Debt                                                                                   447,018                 490,598
                                                                                              -----------             -----------
TOTAL                                                                                            915,546                 978,873
                                                                                              -----------             -----------

                    CURRENT LIABILITIES
--------------------------------------------------------------
Long-term Debt Due Within One Year                                                               100,000                  83,700
Advances from Affiliates                                                                          75,034                  32,864
Accounts Payable:
  General                                                                                         64,367                  48,808
  Affiliated Companies                                                                            61,981                  57,206
Customer Deposits                                                                                 29,499                  26,547
Taxes Accrued                                                                                     35,068                  27,157
Interest Accrued                                                                                   3,447                   3,706
Risk Management Liabilities                                                                        5,034                  11,067
Obligations Under Capital Leases                                                                     494                     452
Other                                                                                             21,294                  35,234
                                                                                              -----------             -----------
TOTAL                                                                                            396,218                 326,741
                                                                                              -----------             -----------

           DEFERRED CREDITS AND OTHER LIABILITIES
--------------------------------------------------------------
Deferred Income Taxes                                                                            347,414                 335,434
Long-Term Risk Management Liabilities                                                              2,177                   3,602
Regulatory Liabilities:
  Asset Removal Costs                                                                            219,101                 214,033
  Deferred Investment Tax Credits                                                                 29,515                  30,411
  SFAS 109 Regulatory Liability, Net                                                              23,719                  24,937
  Other                                                                                            5,085                  15,406
Obligations Under Capital Leases                                                                     620                     558
Deferred Credits and Other                                                                        39,879                  40,037
                                                                                              -----------             -----------
TOTAL                                                                                            667,510                 664,418
                                                                                              -----------             -----------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                          $1,979,274              $1,970,032
                                                                                              ===========             ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                     STATEMENTS OF CASH FLOWS
                                         For the Six Months Ended June 30, 2004 and 2003
                                                           (Unaudited)

                                                                                                 2004                   2003
                                                                                                 ----                   ----
                                                                                                        (in thousands)
<C>                                                                                            <C>                     <C>
                   OPERATING ACTIVITIES
------------------------------------------------------------
Net Income (Loss)                                                                               $(1,612)               $18,618
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows
 From Operating Activities:
   Depreciation and Amortization                                                                 44,335                 42,853
   Deferred Income Taxes                                                                         11,043                 10,940
   Deferred Investment Tax Credits                                                                 (895)                  (895)
   Deferred Property Taxes                                                                      (17,295)               (16,478)
   Mark-to-Market of Risk Management Contracts                                                   10,237                (12,340)
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                                      (5,441)                (5,556)
   Fuel, Materials and Supplies                                                                  (3,557)                   868
   Accounts Payable                                                                              20,334                  1,262
   Taxes Accrued                                                                                  7,911                  5,780
   Fuel Recovery                                                                                (12,683)                11,650
Changes in Other Assets                                                                             157                (11,359)
Changes in Other Liabilities                                                                    (16,478)                 1,145
                                                                                               ---------               --------
Net Cash Flows From Operating Activities                                                         36,056                 46,488
                                                                                               ---------               --------

                   INVESTING ACTIVITIES
------------------------------------------------------------
Construction Expenditures                                                                       (36,645)               (34,660)
Proceeds from Sale of Property and Other                                                            458                    127
Change in Other Cash Deposits, Net                                                                3,566                 (2,843)
                                                                                               ---------               --------
Net Cash Flows Used For Investing Activities                                                    (32,621)               (37,376)
                                                                                               ---------               --------

                   FINANCING ACTIVITIES
------------------------------------------------------------
Capital Contributions from Parent                                                                     -                 50,000
Change in Advances to/from Affiliates, Net                                                       42,170                (17,550)
Retirement of Long-term Debt                                                                   (111,020)               (35,000)
Issuance of Long-term Debt                                                                       83,129                     -
Reacquired Preferred Stock                                                                           (3)                    -
Dividends Paid on Common Stock                                                                  (17,500)                (7,500)
Dividends Paid on Cumulative Preferred Stock                                                       (106)                  (106)
                                                                                               ---------               --------
Net Cash Flows Used For Financing Activities                                                     (3,330)               (10,156)
                                                                                               ---------               --------

Net Increase (Decrease) in Cash and Cash Equivalents                                                105                 (1,044)
Cash and Cash Equivalents at Beginning of Period                                                  3,738                  9,543
                                                                                               ---------               --------
Cash and Cash Equivalents at End of Period                                                       $3,843                 $8,499
                                                                                               =========               ========

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $17,600,000 and $24,107,000 and for income taxes was $(2,695,000)
and $8,975,000 in 2004 and 2003, 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 Financial Statements of Registrant Subsidiaries beginning on page L-1.
</TABLE>
<PAGE>


                       PUBLIC SERVICE COMPANY OF OKLAHOMA
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to PSO's financial statements are combined with the notes to financial
statements for other subsidiary registrants. Listed below are the notes that
apply to PSO. The footnotes begin on page L-1.

                                                               Footnote
                                                               Reference
                                                               ---------

Significant Accounting Matters                                 Note 1

New Accounting Pronouncements                                  Note 2

Rate Matters                                                   Note 3

Commitments and Contingencies                                  Note 5

Guarantees                                                     Note 6

Benefit Plans                                                  Note 8

Business Segments                                              Note 9

Financing Activities                                           Note 10





<PAGE>










                  SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED



<PAGE>



                SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                ------------------------------------------------

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

Net Income decreased $7 million for 2004 year-to-date, but increased $7 million
for the second quarter. The year-to-date decrease is due in large part to a
decline in margins from risk management activities and the $9 million (net of
tax) Cumulative Effect of Accounting Changes recorded in 2003. For the quarter,
the decreased risk management margins were more than offset by increased retail
revenues and a purchased power refund.

Fluctuations occurring in the retail portion of fuel and purchased power expense
generally do not impact operating income, as they are offset in revenues and/or
operations expense due to the functioning of the fuel adjustment clauses in the
states in which we serve.

Second Quarter 2004 Compared to Second Quarter 2003
---------------------------------------------------

Operating Income
----------------

Operating Income increased by $6 million primarily due to:

 o  Increased retail base revenues of $8 million due to an increased number of
    customers and their average usage, offset in part by milder weather.
 o  Decreased fuel expense of 10% due both to lower KWH generation of 4% and
    lower cost per KWH of 6%.
 o  Decreased purchased power of 88% due mainly to a refund of capacity payments
    for prior periods of $8.6 million. Additionally, KWH purchases declined
    17% and the cost per KWH declined by 38%.

The increase in Operating Income was partially offset by:

 o  Decreased retained margins from off-system sales of $2 million due to mainly
    to decreased realization of off-system sales.
 o  Decreased margins from risk management activities of $6 million.
 o  Increased Other Operation expenses of $2 million primarily related to
    transmission expense.
 o  Increased Maintenance expense of $5 million resulting from $3 million of
    overhead line expense primarily related to storm damage, as well as
    scheduled power plant maintenance.
 o  Increased Taxes Other Than Income Taxes of $2 million due primarily to
    higher property taxes.

Other Impacts on Earnings
-------------------------

Interest Charges decreased $2 million as a result of refinancing higher interest
rate debt and trust preferred securities with lower cost debt and trust
preferred securities.

Minority Interest of $1 million is a result of consolidating Sabine Mining
Company (Sabine) effective July 1, 2003, due to implementation of FIN 46. We now
record the depreciation, interest and other operating expenses of Sabine and
eliminate Sabine's revenues against our fuel expenses. While there was no effect
to net income as a result of consolidation, some individual income statement
captions were affected.

Income Taxes

The effective tax rates for the second quarter of 2004 and 2003 were 33.2% and
32.9%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The effective tax rates remained
relatively flat for the comparative period.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
-------------------------------------------------------------------------

Operating Income
----------------

Operating Income was virtually unchanged but negatively impacted by:

 o  Decreased retained margins from off-system sales of $2 million due mainly to
    decreased realization of off-system sales.
 o  Decreased margins from risk management activities of $9 million.
 o  Increased Other Operation expenses of $8 million primarily related to a
    prior year true up for OATT transmission recorded in 2004 resulting from
    revised data from ERCOT for the years 2001-2003 offset in part by lower
    administrative expenses.
 o  Increased Maintenance expense of $8 million primarily related to scheduled
    power plant maintenance, as well as increased overhead line maintenance,
    partly due to increased storm damage.
 o  Increased Depreciation and Amortization expense of $4 million due
    primarily to the restoration in 2003 of a regulatory asset related to the
    recovery of fuel related cost in Arkansas.
 o  Increased Taxes Other Than Income Taxes of $3 million due primarily to
    higher property taxes and state and local franchise taxes.

Operating Income was positively affected by:

 o  Increased retail base revenues of $12 million, 5%, due to an increased
    number of customers and their average usage, offset in part by milder
    weather. Cooling and heating degree-days decreased 4%.
 o  Total purchased power decreased by 66% due mainly to a refund of capacity
    payments for prior periods of $8.6 million.  Additionally, KWH purchases
    declined 19% and the cost per KWH declined 20%.

Other Impacts on Earnings
-------------------------

Interest Charges decreased $3 million as a result of refinancing higher interest
rate debt and trust preferred securities with lower cost debt and trust
preferred securities.

Minority Interest of $2 million is a result of consolidating Sabine effective
July 1, 2003, due to implementation of FIN 46. We now record the depreciation,
interest and other operating expenses of Sabine and eliminate Sabine's revenues
against our fuel expenses. While there was no effect to net income as a result
of consolidation, some individual income statement captions were affected.

The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 and EITF 02-3 in 2003.

Income Taxes
------------

The effective tax rates for the first six months of 2004 and 2003 were 29.3% and
33.1%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to permanent differences relating to book depletion and
Medicare subsidy.

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

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

The rating agencies currently have us on stable outlook. Our first mortgage
bonds were upgraded by S&P to A- due to a change in methodology at the agency.
Current ratings are as follows:

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

Cash Flow
---------

Cash flows for the six months ended June 30, 2004 and 2003 were as follows:

<TABLE>
<CAPTION>

                                                                        2004               2003
                                                                        ----               ----
  <C>                                                                 <C>                <C>
  Cash and cash equivalents at beginning of period                     $5,676                 $-
                                                                      --------           --------
  Cash flows from (used for):
    Operating activities                                              113,340            114,574
    Investing activities                                              (57,360)           (63,575)
    Financing activities                                              (50,054)           (43,674)
                                                                      --------           --------
  Net increase in cash and cash equivalents                             5,926              7,325
                                                                      --------           --------
  Cash and cash equivalents at end of period                          $11,602             $7,325
                                                                      ========           ========
</TABLE>

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

Cash Flows From Operating Activities were $113 million primarily due to Net
Income, Accounts Payable, Fuel Recovery and Taxes Accrued offset in part by
Accounts Receivable, Net and Other Assets and Liabilities.

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

Cash Used for Investing Activities was primarily related to construction
projects for improved transmission and distribution service reliability.

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

Cash Flows Used For Financing Activities through long-term debt issuances and
advances from affiliates were used to replace higher interest rate long-term
debt with lower interest rate long-term debt.

Financing Activity
------------------

Long-term debt issuances and retirements during the first six months of 2004
were:

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

   Installment Purchase Contracts       $53,500          Variable          2019
   Installment Purchase Contracts        41,135          Variable          2011
   Financing Obligations                 14,226            5.77            2024


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

   Installment Purchase Contracts       $53,500            7.60            2019
   Installment Purchase Contracts        12,290            6.90            2004
   Installment Purchase Contracts        12,170            6.00            2008
   Installment Purchase Contracts        17,125            8.20            2011
   First Mortgage Bonds                  80,000            6.875           2025
   First Mortgage Bonds                  40,000            7.75            2004
   Notes Payable                          3,415            4.47            2011
   Notes Payable                          1,500          Variable          2008

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

See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.

Critical Accounting Estimates
-----------------------------

See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report 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
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.

MTM Risk Management Contract Net Assets
---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
<TABLE>
<CAPTION>

                                       MTM Risk Management Contract Net Assets
                                           Six Months Ended June 30, 2004
                                                   (in thousands)

<C>                                                                                                               <C>
 Total MTM Risk Management Contract Net Assets at December 31, 2003                                               $16,606
 (Gain) Loss from Contracts Realized/Settled During the Period (a)                                                 (3,571)
 Fair Value of New Contracts When Entered Into During the Period (b)                                                    -
 Net Option Premiums Paid/(Received) (c)                                                                               73
 Change in Fair Value Due to Valuation Methodology Changes (d)                                                         62
 Changes in Fair Value of Risk Management Contracts (e)                                                            (1,720)
 Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)                       (7,027)
                                                                                                                  --------
 Total MTM Risk Management Contract Net Assets                                                                      4,423
 Net Cash Flow Hedge Contracts (g)                                                                                 (1,309)
                                                                                                                  --------
 Total MTM Risk Management Contract Net Assets at June 30, 2004                                                    $3,114
                                                                                                                  ========
</TABLE>

(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
    includes realized risk management contracts and related derivatives
    that settled during 2004 that were entered into prior to 2004.
(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 2004. 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 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
    represents the impact of AEP changes in methodology in regards to
    credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
    fair value change in the risk management portfolio due to market
    fluctuations during the current period. Market fluctuations are
    attributable to various factors such as supply/demand, weather,
    etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
    Regulated Jurisdictions" relates to the net gains (losses) of those
    contracts that are not reflected in the Consolidated Statements of
    Income. These net gains (losses) are recorded as regulatory
    liabilities/assets for those subsidiaries that operate in regulated
    jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
    Accumulated Other Comprehensive Income (Loss).

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

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

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

<TABLE>
<CAPTION>

                                          Maturity and Source of Fair Value of MTM
                                             Risk Management Contract Net Assets
                                         Fair Value of Contracts as of June 30, 2004

                                               Remainder                                                      After
                                                 2004         2005       2006         2007        2008        2008      Total (c)
                                               ---------      ----       ----         ----        ---         -----     ---------
                                                                                 (in thousands)
<C>                                             <C>         <C>          <C>          <C>         <C>         <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                                $(446)        $44        $(1)        $142          $-          $-        $(261)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                 1,729         936        186            -           -           -        2,851
Prices Based on Models and Other
 Valuation Methods (b)                            (181)        727        (53)         141         301         898        1,833
                                                -------     -------      -----        -----       -----       -----      -------

Total                                           $1,102      $1,707       $132         $283        $301        $898       $4,423
                                                =======     =======      =====        =====       =====       =====      =======

</TABLE>

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


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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.

          Total Accumulated Other Comprehensive Income (Loss) Activity
                     For the Six Months Ended June 30, 2004
                                                                   Power
                                                                   -----
                                                               (in thousands)
   Beginning Balance December 31, 2003                             $184
   Changes in Fair Value (a)                                       (500)
   Reclassifications from AOCI to Net Income (b)                   (118)
                                                                 -------
   Ending Balance June 30, 2004                                   $(434)
                                                                  ======

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

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $278 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:

        Six Months Ended                          Twelve Months Ended
         June 30, 2004                             December 31, 2003
        ----------------                          -------------------
         (in thousands)                             (in thousands)

End     High     Average    Low              End     High   Average    Low
---     ----     -------    ---              ---     ----   -------    ---
$115    $260      $129      $65             $304    $1,182   $495     $118


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $40 million and $57 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.


<PAGE>
<TABLE>
<CAPTION>



                                      SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                            CONSOLIDATED STATEMENTS OF INCOME
                               For the Three and Six Months Ended June 30, 2004 and 2003
                                                      (Unaudited)

                                                                              Three Months Ended             Six Months Ended
                                                                             -------------------            -------------------
                                                                             2004           2003            2004           2003
                                                                             ----           ----            ----           ----
                                                                                             (in thousands)
<C>                                                                        <C>            <C>             <C>            <C>
                  OPERATING REVENUES
-------------------------------------------------------
Electric Generation, Transmission and Distribution                         $251,230       $263,907        $465,179       $487,521
Sales to AEP Affiliates                                                      17,498         17,399          39,709         49,063
                                                                        ------------   ------------     -----------    ----------
TOTAL                                                                       268,728        281,306         504,888        536,584
                                                                         -----------    -----------      ----------     ---------

                  OPERATING EXPENSES
-------------------------------------------------------
Fuel for Electric Generation                                                 94,245        104,979         183,068        204,618
Purchased Electricity for Resale                                             (4,008)        10,365           1,926         22,932
Purchased Electricity from AEP Affiliates                                     7,113         14,841          14,420         25,651
Other Operation                                                              44,273         42,383          94,540         86,611
Maintenance                                                                  24,011         18,931          39,659         31,748
Depreciation and Amortization                                                31,979         30,868          63,264         58,903
Taxes Other Than Income Taxes                                                15,148         13,168          31,715         29,041
Income Taxes                                                                 14,439         10,183          14,570         15,448
                                                                           ---------      ---------       ---------      ---------
TOTAL                                                                       227,200        245,718         443,162        474,952
                                                                           ---------      ---------       ---------      ---------

OPERATING INCOME                                                             41,528         35,588          61,726         61,632

Nonoperating Income                                                             792            475           2,195          1,347
Nonoperating Expenses                                                         1,240            355           2,066            876
Nonoperating Income Tax (Credit)                                               (541)          (105)           (897)           (55)
Interest Charges                                                             12,862         15,223          28,090         31,077
Minority Interest                                                               813              -           1,694              -
                                                                           ---------      ---------       ---------      ---------

Income Before Cumulative Effect of Accounting Changes                        27,946         20,590          32,968         31,081
Cumulative Effect of Accounting Changes (Net of Tax)                              -              -               -          8,517
                                                                           ---------      ---------       ---------      ---------

NET INCOME                                                                   27,946         20,590          32,968         39,598

Preferred Stock Dividend Requirements                                            58             58             115            115
                                                                           ---------      ---------       ---------      ---------

EARNINGS APPLICABLE TO COMMON STOCK                                         $27,888        $20,532         $32,853        $39,483
                                                                           =========      =========       =========      =========


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

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



                                        SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                   CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                EQUITY AND COMPREHENSIVE INCOME
                                        For the Six Months Ended June 30, 2004 and 2003
                                                       (in thousands)
                                                         (Unaudited)


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

<C>                                                  <C>             <C>              <C>                <C>              <C>
DECEMBER 31, 2002                                     $135,660       $245,003         $334,789            $(53,683)       $661,769

Common Stock Dividends                                                                 (36,396)                            (36,396)
Preferred Stock Dividends                                                                 (115)                               (115)
                                                                                                                          ---------
TOTAL                                                                                                                      625,258
                                                                                                                          ---------

           COMPREHENSIVE INCOME
------------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
  Cash Flow Hedges                                                                                         (1,004)          (1,004)
NET INCOME                                                                              39,598                              39,598
                                                                                                                          ---------
TOTAL COMPREHENSIVE INCOME                                                                                                  38,594
                                                     ---------       ---------        ---------          ---------        ---------

JUNE 30, 2003                                         $135,660       $245,003         $337,876           $(54,687)        $663,852
                                                     =========       =========        =========          =========        =========


DECEMBER 31, 2003                                     $135,660       $245,003         $359,907           $(43,910)        $696,660

Common Stock Dividends                                                                 (30,000)                            (30,000)
Preferred Stock Dividends                                                                 (115)                               (115)
                                                                                                                          ---------
TOTAL                                                                                                                      666,545
                                                                                                                          ---------

           COMPREHENSIVE INCOME
------------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
  Cash Flow Hedges                                                                                           (618)            (618)
  Minimum Pension Liability                                                                                23,066           23,066
NET INCOME                                                                              32,968                              32,968
                                                                                                                          ---------
TOTAL COMPREHENSIVE INCOME                                                                                                  55,416
                                                     ---------       ---------        ---------          ---------        ---------

JUNE 30, 2004                                        $135,660        $245,003         $362,760           $(21,462)        $721,961
                                                     =========       =========        =========          =========        =========

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


                                         SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                   CONSOLIDATED BALANCE SHEETS
                                                            ASSETS
                                            June 30, 2004 and December 31, 2003
                                                          (Unaudited)

                                                                                                   2004                  2003
                                                                                                   ----                  ----
                                                                                                        (in thousands)

<C>                                                                                             <C>                   <C>
                ELECTRIC UTILITY PLANT
-----------------------------------------------------
Production                                                                                      $1,657,785            $1,622,498
Transmission                                                                                       629,662               615,158
Distribution                                                                                     1,097,960             1,078,368
General                                                                                            445,896               423,427
Construction Work in Progress                                                                       31,100                60,009
                                                                                                -----------           -----------
TOTAL                                                                                            3,862,403             3,799,460
Accumulated Depreciation and Amortization                                                        1,673,188             1,617,846
                                                                                                -----------           -----------
TOTAL - NET                                                                                      2,189,215             2,181,614
                                                                                                -----------           -----------

             OTHER PROPERTY AND INVESTMENTS
-----------------------------------------------------
Non-Utility Property, Net                                                                            4,050                 3,808
Other Investments                                                                                    4,710                 4,710
                                                                                                -----------           -----------
TOTAL                                                                                                8,760                 8,518
                                                                                                -----------           -----------

                    CURRENT ASSETS
-----------------------------------------------------
Cash and Cash Equivalents                                                                           11,602                 5,676
Other Cash Deposits                                                                                  5,245                 6,048
Advances to Affiliates                                                                                   -                66,476
Accounts Receivable:
  Customers                                                                                         42,103                41,474
  Affiliated Companies                                                                              17,484                10,394
  Miscellaneous                                                                                      4,018                 4,682
  Allowance for Uncollectible Accounts                                                              (4,675)               (2,093)
Fuel Inventory                                                                                      59,898                63,881
Materials and Supplies                                                                              35,675                33,775
Regulatory Asset for Under-recovered Fuel Costs                                                      4,822                11,394
Risk Management Assets                                                                               7,734                19,715
Margin Deposits                                                                                        437                 5,123
Prepayments and Other                                                                               18,252                19,078
                                                                                                -----------           -----------
TOTAL                                                                                              202,595               285,623
                                                                                                -----------           -----------

           DEFERRED DEBITS AND OTHER ASSETS
-----------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Asset, Net                                                                     5,281                 3,235
  Unamortized Loss on Reacquired Debt                                                               22,161                19,331
  Minimum Pension Liability                                                                         35,486                     -
  Other                                                                                             15,195                15,859
Long-term Risk Management Assets                                                                     4,512                12,178
Deferred Charges                                                                                    71,580                55,605
                                                                                                -----------           -----------
TOTAL                                                                                              154,215               106,208
                                                                                                -----------           -----------

TOTAL ASSETS                                                                                    $2,554,785            $2,581,963
                                                                                                ===========           ===========

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


                                            SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                      CONSOLIDATED BALANCE SHEETS
                                                     CAPITALIZATION AND LIABILITIES
                                                  June 30, 2004 and December 31, 2003
                                                              (Unaudited)

                                                                                                     2004                  2003
                                                                                                     ----                  ----
                                                                                                           (in thousands)
<C>                                                                                              <C>                   <C>
                    CAPITALIZATION
---------------------------------------------------------------
Common Shareholder's Equity:
  Common Stock - $18 Par Value:
     Authorized - 7,600,000 Shares
     Outstanding - 7,536,640 Shares                                                                $135,660              $135,660
     Paid-in Capital                                                                                245,003               245,003
     Retained Earnings                                                                              362,760               359,907
     Accumulated Other Comprehensive Income (Loss)                                                  (21,462)              (43,910)
                                                                                                 -----------           -----------
Total Common Shareholder's Equity                                                                   721,961               696,660
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                        4,700                 4,700
                                                                                                 -----------           -----------
Total Shareholder's Equity                                                                          726,661               701,360
Long-term Debt                                                                                      763,486               741,594
                                                                                                 -----------           -----------
TOTAL                                                                                             1,490,147             1,442,954
                                                                                                 -----------           -----------

Minority Interest                                                                                     1,280                 1,367
                                                                                                 -----------           -----------

                 CURRENT LIABILITIES
---------------------------------------------------------------
Long-term Debt Due Within One Year                                                                   10,244               142,714
Advances from Affiliates                                                                             26,918                     -
Accounts Payable:
  General                                                                                            43,740                37,646
  Affiliated Companies                                                                               32,558                35,138
Customer Deposits                                                                                    26,731                24,260
Taxes Accrued                                                                                        75,180                28,691
Interest Accrued                                                                                     11,848                16,852
Risk Management Liabilities                                                                           6,239                11,361
Obligations Under Capital Leases                                                                      3,420                 3,159
Regulatory Liability for Over-recovered Fuel                                                          6,204                 4,178
Other                                                                                                32,867                53,753
                                                                                                 -----------           -----------
TOTAL                                                                                               275,949               357,752
                                                                                                 -----------           -----------

          DEFERRED CREDITS AND OTHER LIABILITIES
---------------------------------------------------------------
Deferred Income Taxes                                                                               358,813               349,064
Long-term Risk Management Liabilities                                                                 2,893                 4,667
Reclamation Reserve                                                                                   7,632                16,512
Regulatory Liabilities:
  Asset Removal Costs                                                                               243,305               236,409
  Deferred Investment Tax Credits                                                                    37,701                39,864
  Excess Earnings                                                                                     2,600                 2,600
  Other                                                                                               7,870                18,779
Asset Retirement Obligations                                                                         26,665                 8,429
Obligations Under Capital Leases                                                                     18,139                18,383
Deferred Credits and Other                                                                           81,791                85,183
                                                                                                 -----------           -----------
TOTAL                                                                                               787,409               779,890
                                                                                                 -----------           -----------

Commitments and Contingencies (Note 5)

TOTAL CAPITALIZATION AND LIABILITIES                                                             $2,554,785            $2,581,963
                                                                                                 ===========           ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                             SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                  CONSOLIDATED STATEMENTS OF CASH FLOWS
                                             For the Six Months Ended June 30, 2004 and 2003
                                                               (Unaudited)

                                                                                                   2004                  2003
                                                                                                   ----                  ----
                                                                                                          (in thousands)
<C>                                                                                              <C>                    <C>
                  OPERATING ACTIVITIES
---------------------------------------------------
Net Income                                                                                        $32,968               $39,598
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
    Cumulative Effect of Accounting Changes                                                             -                (8,517)
    Depreciation and Amortization                                                                  63,264                58,903
    Deferred Income Taxes                                                                          (4,519)                2,413
    Deferred Investment Tax Credits                                                                (2,163)               (2,163)
    Deferred Property Taxes                                                                       (19,375)              (18,630)
    Mark-to-Market of Risk Management Contracts                                                    12,181               (13,945)
Changes in Certain Assets and Liabilities:
    Accounts Receivable, Net                                                                       (4,473)                9,696
    Fuel, Materials and Supplies                                                                    2,083                 7,445
    Accounts Payable                                                                                3,514               (12,349)
    Taxes Accrued                                                                                  46,489                23,792
    Fuel Recovery                                                                                   8,598               (14,148)
Change in Other Assets                                                                             (6,049)               10,887
Change in Other Liabilities                                                                       (19,178)               31,592
                                                                                                 ---------              --------
Net Cash Flows From Operating Activities                                                          113,340               114,574
                                                                                                 ---------              --------

                 INVESTING ACTIVITIES
---------------------------------------------------
Construction Expenditures                                                                         (60,479)              (62,883)
Proceeds from Sale of Assets and Other                                                              2,316                   414
Change in Other Cash Deposits, Net                                                                    803                (1,106)
                                                                                                 ---------              --------
Net Cash Flows Used For Investing Activities                                                      (57,360)              (63,575)
                                                                                                 ---------              --------

                 FINANCING ACTIVITIES
---------------------------------------------------
Issuance of Long-term Debt                                                                        106,667               143,041
Retirement of Long-term Debt                                                                     (220,000)              (56,020)
Change in Advances to/from Affiliates, Net                                                         93,394               (94,184)
Dividends Paid on Common Stock                                                                    (30,000)              (36,396)
Dividends Paid on Cumulative Preferred Stock                                                         (115)                 (115)
                                                                                                 ---------              --------
Net Cash Flows Used For Financing Activities                                                      (50,054)              (43,674)
                                                                                                 ---------              --------

Net Increase in Cash and Cash Equivalents                                                           5,926                 7,325
Cash and Cash Equivalents at Beginning of Period                                                    5,676                     -
                                                                                                 ---------              --------
Cash and Cash Equivalents at End of Period                                                        $11,602                $7,325
                                                                                                 =========              ========

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $29,841,000 and $27,741,000 and for income taxes was $3,220,000 and
$17,062,000 in 2004 and 2003, respectively.

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


                SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
        INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
        -----------------------------------------------------------------

The notes to SWEPCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below
are the notes that apply to SWEPCo. The footnotes begin on page L-1.

                                                                  Footnote
                                                                  Reference
                                                                  ---------

Significant Accounting Matters                                    Note 1

New Accounting Pronouncements                                     Note 2

Rate Matters                                                      Note 3

Customer Choice and Industry Restructuring                        Note 4

Commitments and Contingencies                                     Note 5

Guarantees                                                        Note 6

Benefit Plans                                                     Note 8

Business Segments                                                 Note 9

Financing Activities                                              Note 10



<PAGE>
<TABLE>
<CAPTION>


                  NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
                  --------------------------------------------------------


The notes to financial statements that follow are a combined presentation for
AEP's registrant subsidiaries. The following list indicates the registrants to
which the footnotes apply:

<C>   <C>                                   <C>
1.    Significant Accounting Matters        AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

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

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 Contingencies         AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

6.    Guarantees                            AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

7.    Dispositions and Assets Held          TCC
       for Sale

8.    Benefit Plans                         APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

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

10.   Financing Activities                  AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

</TABLE>

<PAGE>

1.  SIGNIFICANT ACCOUNTING MATTERS
    ------------------------------

General
-------

The accompanying unaudited interim financial statements should be read
in conjunction with the 2003 Annual Report as incorporated in and filed
with our 2003 Form 10-K.

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

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

Accumulated Other Comprehensive Income (Loss) is included on the balance
sheet in the equity section. The components of Accumulated Other
Comprehensive Income (Loss) for AEP registrant subsidiaries is shown in
the following table.

                                             June 30,            December 31,
   Components                                  2004                 2003
   -----------                                 ----                 ----
                                                     (in thousands)
   Cash Flow Hedges:
           APCo                              $(6,031)            $(1,569)
           CSPCo                              (2,195)                202
           I&M                                (2,756)                222
           KPCo                                 (542)                420
           OPCo                               (3,345)               (103)
           PSO                                  (370)                156
           SWEPCo                               (434)                184
           TCC                               (11,242)             (1,828)
           TNC                                (3,765)               (601)

   Minimum Pension Liability:
           APCo                             $(50,519)           $(50,519)
           CSPCo                             (46,529)            (46,529)
           I&M                               (25,328)            (25,328)
           KPCo                               (6,633)             (6,633)
           OPCo                              (52,646)            (48,704)
           PSO                               (43,998)            (43,998)
           SWEPCo                            (21,027)            (44,094)
           TCC                               (62,511)            (60,044)
           TNC                               (26,117)            (26,117)

During the first quarter of 2004, SWEPCo reclassified $23 million from
Accumulated Other Comprehensive Income (Loss) related to minimum pension
liability to Regulatory Assets ($35 million) and Deferred Income Taxes
($12 million) as a result of authoritative letters issued by the FERC
and the Arkansas and Louisiana commissions.

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.

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         June 30,
                                       2004             Accretion             Incurred            2004
                                     ----------         ---------            -----------       ----------
                                                                  (in millions)
     <C>                              <C>                  <C>                 <C>               <C>
     AEGCo (a)                         $1.1                $0.1                  $-               $1.2
     APCo (a)                          21.7                 0.9                   -               22.6
     CSPCo (a)                          8.7                 0.4                   -                9.1
     I&M (b)                          553.2                19.6                   -              572.8
     OPCo (a)                          42.7                 1.6                   -               44.3
     SWEPCo (d)                         8.4                 0.6                17.7               26.7
     TCC (c)                          218.8                 8.2                   -              227.0

</TABLE>

      (a) Consists of asset retirement obligations related to ash ponds.
      (b) Consists of asset retirement obligations related to ash ponds
          ($1.2 million at June 30, 2004) and nuclear decommissioning costs
          for the Cook Plant ($571.6 million at June 30, 2004).
      (c) Consists of asset retirement obligations related to nuclear
          decommissioning costs for STP included in Liabilities Held for Sale
          - Texas Generation Plants on TCC's Consolidated Balance Sheets.
      (d) Consists of asset retirement obligations related to Sabine Mining and
          Dolet Hills.

Accretion expense is included in Other Operation expense in the
respective income statements of the individual subsidiary registrants.

As of June 30, 2004 and December 31 2003, the fair value of assets that
are legally restricted for purposes of settling the nuclear
decommissioning liabilities totaled $885 million ($754 million for I&M
and $131 million for TCC) and $845 million ($720 million for I&M and
$125 million for TCC), respectively, recorded in Nuclear Decommissioning
and Spent Nuclear Fuel Disposal Trust Funds on I&M's Consolidated
Balance Sheets and in Assets Held for Sale-Texas Generation Plants on
TCC's Consolidated Balance Sheets.

Reclassification
----------------

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

2.  NEW ACCOUNTING PRONOUNCEMENTS
    -----------------------------

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

We implemented FIN 46R, "Consolidation of Variable Interest Entities,"
effective March 31, 2004 with no material impact to our financial
statements. FIN 46R is a revision to FIN 46 which 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.

FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements
 Related to the Medicare Prescription Drug Improvement and Modernization Act
 of 2003
----------------------------------------------------------------------------

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC implemented FASB
Staff Position (FSP) FAS 106-2, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization
Act of 2003," effective April 1, 2004, retroactive to January 1, 2004.
The new disclosure standard provides authoritative guidance on the
accounting for any effects of the Medicare prescription drug subsidy
under the Act. It replaces the earlier FSP FAS 106-1, under which APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC previously elected to
defer accounting for any effects of the Act until the FASB issued
authoritative guidance on the accounting for the Medicare subsidy.

Under FSP FAS 106-2, the current portion of the Medicare subsidy for
employers who qualify for the tax-free subsidy is a reduction of ongoing
FAS 106 cost, while the retroactive portion is an actuarial gain to be
amortized over the average remaining service period of active employees,
to the extent that the gain exceeds FAS 106's 10 percent corridor. The
Medicare subsidy reduced the FAS 106 accumulated postretirement benefit
obligation (APBO) related to benefits attributed to past service by $202
million. The tax-free subsidy reduced AEP's second quarter net periodic
postretirement benefit cost by a total of $7 million, including $3
million of amortization of the actuarial gain, $1 million of reduced
service cost, and $3 million of reduced interest cost on the APBO. After
adjustment to capitalization of employee benefits costs as of a cost of
construction projects, $5 million of this tax-free cost reduction
remained to increase AEP's second quarter net income.

The following table provides the reduction in the net periodic
postretirement benefit cost for the second quarter of 2004 for the AEP
registrant subsidiaries:

                                              Postretirement Benefit
                                                  Cost Reduction
                                              ----------------------
                                                  (in thousands)
       APCo                                            $815
       CSPCo                                            413
       I&M                                              632
       KPCo                                             121
       OPCo                                             720
       PSO                                              281
       SWEPCo                                           291
       TCC                                              327
       TNC                                              143

The effect of implementing FSP FAS 106-2 on AEP for the first quarter of 2004
is as follows:

 Three Months Ended March, 31, 2004   Earnings in Millions   Earnings Per Share
 ----------------------------------   --------------------   ------------------

 Originally Reported                           $278                $0.70
 Effect of Medicare Subsidy                       5                 0.02
                                               -----              ------
 Restated                                      $283                $0.72
                                               =====               =====

        The effect of implementing FSP FAS 106-2 by the following AEP registrant
subsidiaries for the first quarter of 2004 is as follows:


                       Originally            Effect of
                      Reported Net           Medicare          Restated
                      Income (Loss)           Subsidy       Net Income (Loss)
                      -------------          ---------      -----------------
                                          (in thousands)
       APCo            $64,521                 $815            $65,336
       CSPCo            44,705                  413             45,118
       I&M              42,376                  632             43,008
       KPCo             11,490                  121             11,611
       OPCo             79,444                  720             80,164
       PSO              (9,284)                 281             (9,003)
       SWEPCo            4,730                  291              5,021
       TCC              29,077                  327             29,404
       TNC              12,953                  143             13,096

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

The FASB's standard-setting process is ongoing and 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. The FASB is currently working on several projects including
discontinued operations, business combinations, liabilities and equity,
revenue recognition, accounting for equity-based compensation, pension
plans, asset retirement obligations, earnings per share calculations,
fair value measurements, and related tax impacts. We also expect to see
more projects as a result of the FASB's desire to converge International
Accounting Standards with those generally accepted in the United States
of America. The ultimate pronouncements resulting from these and future
projects could have an impact on our future results of operations and
financial position.

3.  RATE MATTERS
    ------------
As discussed in our 2003 Annual Report, rate and regulatory proceedings
at the FERC and at several state commissions are ongoing. The Rate
Matters note within our 2003 Annual Report should be read in conjunction
with this report in order to gain a complete understanding of material
rate matters still pending, without significant changes since year-end.
The following sections discuss current activities.

TNC Fuel Reconciliation - Affecting  TNC
----------------------------------------

In 2002, TNC filed with the PUCT to reconcile fuel costs, requesting to
defer any unrecovered portion applicable to retail sales within its
ERCOT service area for inclusion in the 2004 true-up proceeding. This
reconciliation for the period from July 2000 through December 2001 will
be the final fuel reconciliation for TNC's ERCOT service territory.

In March 2003, the ALJ in this proceeding filed a Proposal for Decision
(PFD) with a recommendation that TNC's under-recovered retail fuel
balance be reduced. In March 2003, TNC established a reserve of $13
million based on the recommendations in the PFD. In May 2003, the PUCT
reversed the ALJ on certain matters and remanded TNC's final fuel
reconciliation to the ALJ to consider two issues: (1) the sharing of
off-system sales margins from AEP's trading activities with customers
for five years per the PUCT's interpretation of the Texas AEP/CSW merger
settlement and (2) the inclusion of January 2002 fuel factor revenues
and associated costs in the determination of the under-recovery. The
PUCT proposed that the sharing of off-system sales margins for periods
beyond the termination of the fuel factor should be recognized in the
final fuel reconciliation proceeding. This would result in the sharing
of margins for an additional three and one-half years after the end of
the Texas ERCOT fuel factor. While management believes that the Texas
merger settlement only provided for sharing of margins during the period
fuel and generation costs were regulated by the PUCT, an additional
provision of $10 million was recorded in December 2003.

In December 2003, the ALJ issued a PFD in the remand phase of the TNC
fuel reconciliation recommending additional disallowances for the two
remand issues. TNC filed responses to the PFD and the PUCT announced a
final ruling in the fuel reconciliation proceeding in January 2004
accepting the PFD. TNC received a written order in March 2004 and
increased the reserve by $1.5 million. In March 2004, various parties,
including TNC, requested a rehearing of the PUCT's ruling. In May 2004,
the PUCT reversed its position on the inclusion of MTM amounts in the
allocation of system sales margins and remanded the case to the ALJ. As
a result, TNC recorded an additional provision of $12 million in the
second quarter of 2004 resulting in an over-recovery balance of $7
million at June 30, 2004.

On July 2, 2004, the parties to the MTM remand proceeding filed a
"Stipulation of Fact." All parties agreed to the amount of the remanded
issue. If the amounts included in the "Stipulation of Fact" are
approved, the over-recovery balance will be reduced to $4 million. We
expect the PUCT to issue its final order in this proceeding in August
2004.

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

In 2002, TCC filed its final fuel reconciliation with the PUCT to
reconcile fuel costs to be included in its deferred over-recovery
balance in the 2004 true-up proceeding. This reconciliation covers the
period from July 1998 through December 2001.

Based on the PUCT ruling in the TNC proceeding relating to similar
issues, TCC established a reserve for potential adverse rulings of $81
million during 2003. On February 3, 2004, the ALJ issued a PFD
recommending that the PUCT disallow $140 million in eligible fuel costs
including some new items not considered in the TNC case, and other items
considered but not disallowed in the TNC ruling. Based on an analysis of
the ALJ's recommendations, TCC established an additional reserve of $13
million during the first quarter of 2004. In May 2004, the PUCT accepted
most of the ALJ's recommendations. The PUCT rejected the ALJ's
recommendation to impute capacity to certain energy-only purchased power
contracts and remanded the issue to the ALJ to determine if any energy-
only purchased power contracts during the reconciliation period include
a capacity component that is not recoverable in fuel revenues. Hearings
are scheduled in October 2004 for the remand issue. As a result of the
PUCT's acceptance of the ALJ's recommendations and the PUCT's remand
decision in the TNC case regarding the inclusion of MTM amounts in the
allocation of AEP's net system sales margins, TCC increased its
provision by $47 million in the second quarter of 2004. The
over-recovery balance and the provisions total $210 million including
interest at June 30, 2004. At this time, management is unable to predict
the outcome of this proceeding. An adverse ruling from the PUCT,
disallowing amounts in excess of the established reserve, could have a
material impact on future results of operations and cash flows.
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 in the
SPP. This reconciliation covers the period from January 2000 through
December 2002. During the reconciliation period, SWEPCo incurred $435
million of Texas retail eligible fuel expense. In November 2003,
intervenors and the PUCT Staff recommended fuel cost disallowances of
more than $30 million. In December 2003, SWEPCo agreed to a settlement
in principle with all parties in the fuel reconciliation. The settlement
provides for a disallowance in fuel costs of $8 million which was
recorded in December 2003. In April 2004, the PUCT approved the
settlement.

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

On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates
should not be reduced. Other municipalities served by TCC passed similar
rate review resolutions. In Texas, municipalities have original
jurisdiction over rates of electric utilities within their municipal
limits. Under Texas law, TCC must provide support for its rates to the
municipalities. TCC filed the requested support for its rates based on a
test year ending June 30, 2003 with all of its municipalities and the
PUCT on November 3, 2003. TCC's proposal would decrease its wholesale
transmission rates by $2 million or 2.5% and increase its retail energy
delivery rates by $69 million or 19.2%. In February 2004, eight
intervening parties and the PUCT Staff filed testimony recommending
reductions to TCC's requested $67 million rate increase. The
recommendations ranged from a decrease in existing rates of
approximately $100 million to an increase in TCC's current rates of
approximately $27 million. Hearings were held in March 2004. In May
2004, TCC agreed to a non-unanimous settlement on cost of capital
including capital structure and return on equity with all but two
parties in the proceeding. TCC agreed that the return on equity should
be established at 10.125% based upon a capital structure with 40% equity
resulting in a weighted cost of capital of 7.475%. The settlement and
other agreed adjustments reduced TCC's rate request to $41 million. The
ALJs that heard the case issued their recommendations on July 2, 2004
including a recommendation to approve the cost of capital settlement.
The ALJs recommended that an issue related to the allocation of
consolidated tax savings to the transmission and distribution utility be
remanded for additional evidence. On July 15, 2004, the PUCT agreed to
remand this issue to the ALJs. In addition, the PUCT ordered TCC to
calculate its revenue requirements based upon the recommendations of the
ALJs. On July 21, 2004, TCC filed its revenue requirements based upon
the recommendations of the ALJs. According to TCC's calculations, the ALJs'
recommendations reduce TCC's existing rates by a range of $33 million to $43
million depending on the final resolution of the amount of consolidation tax
savings. TCC filed exceptions to the ALJs' recommendations on July 21, 2004.
The PUCT is expected to issue its decision in September 2004. Management is
unable to predict the ultimate effect of this proceeding on TCC's rates,
revenues, results of operations, cash flows and financial condition.

Louisiana Compliance Filing -  Affecting SWEPCo
-----------------------------------------------

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

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

In 2002, PSO experienced a $44 million under-recovery of fuel costs
resulting from a reallocation among AEP West companies of purchased
power costs for periods prior to January 1, 2002. In July 2003, PSO
filed with the Corporation Commission of the State of Oklahoma (OCC)
seeking to recover these costs over a period of 18 months. In August
2003, the OCC Staff filed testimony recommending PSO be granted recovery
of $42.4 million over three years. In September 2003, the OCC expanded
the case to include a full review of PSO's 2001 fuel and purchased power
practices. PSO filed its testimony in February 2004. An intervenor and
the OCC Staff filed testimony in April 2004. The intervenor suggested
$8.8 million related to the 2002 reallocation not be recovered from
customers. The Attorney General of Oklahoma also filed a statement of
position, indicating allocated trading margins between and among AEP
operating companies were inconsistent with the FERC-approved Operating
Agreement and System Integration Agreement and could more than offset
the $44 million 2002 reallocation. The intervenor and the OCC Staff also
believed trading margins were allocated incorrectly and that a
reallocation by the intervenors of such margins would reduce PSO's
recoverable fuel by approximately $6.8 million for 2000 and $10.7
million for 2001, while under the OCC Staff method, the amount for 2001
would be $8.8 million. The intervenor and the OCC Staff also recommend
recalculation of fuel for years subsequent to 2001 using the same
methods. At a June 2004 prehearing conference, PSO questioned whether
the issues in dispute were the jurisdiction of the OCC or the FERC
because they relate to the FERC-approved agreements. As a result, the
ALJ ordered that the jurisdictional issue be briefed by the parties.
PSO is required to file its brief by September 1, 2004. Subject to
decisions by the OCC as to jurisdiction, a hearing date has been set
for January 2005. Management believes that fuel costs have been
prudently incurred consistent with OCC rules, and that the allocation of
trading margins pursuant to the agreements is correct. If the OCC
determines, as a result of the review that a portion of PSO's fuel and
purchased power costs should not be recovered, there will be an adverse
effect on PSO's results of operations, cash flows and possibly financial
condition.

RTO Formation/Integration - 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 $33 million of RTO formation
and integration costs and related carrying charges through June 30,
2004. Amounts per company are as follows:

                    Company                      (in millions)
                    -------                      -------------
                    APCo                             $9.4
                    CSPCo                             3.9
                    I&M                               7.2
                    KPCo                              2.2
                    OPCo                             10.3

As a result of the subsequent delay in the integration of AEP's East
transmission system into PJM, FERC declined to rule, in its July 2003
order, on our request to transfer the deferrals to regulatory assets,
and to maintain the deferrals until such time as the costs can be
recovered from all users of AEP's East transmission system. The AEP East
companies plan to apply for permission to transfer the deferred
formation/integration costs to a regulatory asset prior to integration
with PJM.

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 prudently incurred deferred RTO
formation/integration 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 as these companies file rate cases. Presently, retail base
rates are frozen or capped and cannot be increased for retail customers
of CSPCo, I&M and OPCo.

In August 2004, we intend to file an application with FERC dividing the
RTO information/integration costs between payments made to PJM and all
other costs. We will subsequently request that the payments made
directly to PJM be recovered from all users of PJM's transmission and
that the balance of the deferred costs be recovered from load serving
entities within the area served by the AEP East companies' owned
transmission (AEP zone). Most of the amount recoverable in the AEP zone
will be paid by the AEP East companies since it will be attributable to
their internal load. The amount to be recovered in the AEP zone is
approximately one-half of the deferred costs. In our August application,
we will seek permission to delay the amortization of the AEP zone
deferred amounts until they are recoverable from users of the
transmission system including our retail customers or, as an
alternative, to use a long amortization period that extends beyond the
rate freezes or caps.

The AEP East companies are scheduled to join PJM in October 2004,
although there are pending proceedings in Virginia concerning the
integration into PJM. Therefore, 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 or a
long enough amortization period to allow for the opportunity for
recovery in the East retail jurisdictions. If the AEP East companies do
not obtain regulatory approval to join PJM, we are committed to
reimburse PJM for certain project implementation costs (presently
estimated at $24 million for AEP's share of the entire PJM integration
project). If incurred, PJM project implementation costs will be
allocated among the AEP East companies. Management intends to seek
recovery of the project implementation cost reimbursements, if incurred.
If the FERC ultimately decides not to approve a delay or a long
amortization period or the FERC or the state commissions deny recovery,
future results of operations and cash flows could be adversely affected.

In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO prior to July 1, 2004 and thereafter
only with the approval of the Virginia SCC, but required such transfers
by January 1, 2005. In January 2004, APCo filed with the Virginia SCC a
cost/benefit study covering the time period through 2014 as required by
the Virginia SCC. The study results show a net benefit of approximately
$98 million for APCo over the 11-year study period from AEP's
participation in PJM. In July 2004, after reaching a unanimous agreement
with intervenors to settle the RTO issues in Virginia, the settlement
agreement was submitted to the Virginia SCC. The settlement provides for
approval of APCo's application to join PJM in exchange for a small
annual revenue credit to customers through 2010, or the effective date
of rates established in a new base rate case, some service curtailment
provisions and annual reporting requirements.

In July 2003, the KPSC denied KPCo's request to join PJM based in part
on a lack of evidence that it would benefit Kentucky retail customers.
In August 2003, KPCo sought and was granted a rehearing to submit
additional evidence. In December 2003, AEP filed with the KPSC a
cost/benefit study showing a net benefit of approximately $13 million
for KPCo over the five-year study period from AEP's participation in
PJM. In April 2004, we reached an agreement with interveners to settle
the RTO issues in Kentucky. The KPSC approved the agreement in May 2004
and the FERC approved the settlement in June 2004.

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

In November 2003, the FERC issued an order preliminarily finding that
AEP must fulfill its CSW merger condition to join an RTO by integrating
into PJM (transmission and markets) by October 1, 2004. The order was
based on PURPA 205(a), which allows FERC to exempt electric utilities
from state law or regulation in certain circumstances. The FERC set
several issues for public hearing before an ALJ. Those issues include
whether the laws, rules, or regulations of Virginia and Kentucky are
preventing AEP from joining an RTO and whether the exceptions under
PURPA 205(a) apply. The FERC ALJ affirmed the FERC's preliminary finding
in March 2004. The FERC issued an order related to this matter in June
2004 affirming its preliminary findings. Virginia has requested a stay
of the FERC order, which was denied, and Virginia now has requested a
stay in the courts.

FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo, I&M, KPCo
 and OPCo
-------------------------------------------------------------------------------

In July 2003, the FERC issued an order directing PJM and the Midwest
Independent System Operator (ISO) to make compliance filings for their
respective OATTs to eliminate the transaction-based charges for through
and out (T&O) transmission service on transactions where the energy is
delivered within the proposed Midwest ISO and PJM expanded regions (RTO
Footprint). The elimination of the T&O rates will reduce the
transmission service revenues collected by the RTOs and thereby reduce
the revenues received by transmission owners under the RTOs' revenue
distribution protocols. The order provided that affected transmission
owners could file to offset the elimination of these revenues by
increasing rates or utilizing a transitional rate mechanism to recover
lost revenues that result from the elimination of the T&O rates. The
FERC also found that the T&O rates of some of the former Alliance RTO
companies, including AEP, may be unjust, unreasonable, and unduly
discriminatory or preferential for energy delivered in the RTO
Footprint. FERC initiated an investigation and hearing in regard to
these rates.

In November 2003, the FERC adopted a new regional rate design and
directed each transmission provider to file compliance rates to
eliminate T&O rates prospectively within the region and simultaneously
implement new seams elimination cost allocation (SECA) rates to mitigate
the lost revenues for a two-year transition period beginning April 1,
2004. The FERC was expected to implement a new rate design after the
two-year period. As required by the FERC, AEP filed compliance tariff
changes in January 2004 to eliminate the T&O charges within the RTO
Footprint. Various parties raised issues with the SECA rate orders and
the FERC implemented settlement procedures before an ALJ.

In March 2004, the FERC approved a settlement that delays elimination of
T&O rates until December 1, 2004 and provides principles and procedures
for a new rate design for the RTO Footprint, to be effective on December
1, 2004. The settlement also provides that if the process does not
result in the implementation of a new rate design on December 1, then
the SECA rates will be implemented and will remain in effect until a new
rate is implemented by the FERC. If implemented, the SECA rate would not
be effective beyond March 31, 2006. The AEP East companies received
approximately $157 million of T&O rate revenues from transactions
delivering energy to customers in the RTO Footprint for the twelve
months ended December 31, 2003. At this time, management is unable to
predict whether the new rate design will fully compensate the AEP East
companies for their lost T&O rate revenues and, consequently, their
impact on future results of operations, cash flows and financial
condition.

Indiana Fuel Order - Affecting I&M
----------------------------------

On August 27, 2003, the IURC ordered that certain parties must negotiate
the appropriate action on I&M's fuel cost recovery beginning March 1,
2004, following the February 2004 expiration of a fixed fuel adjustment
charge (fixed pursuant to a prior settlement of the Cook Nuclear Plant
outage issues). The fixed fuel adjustment charge capped fuel recoveries.
In an agreement in connection with AEP's planned corporate separation,
I&M agreed, contingent on AEP implementing the corporate separation,
to a fixed fuel adjustment charge beginning March 2004 and continuing
through December 2007. Although AEP has not corporately separated,
certain parties believe the fixed fuel adjustment charge should
continue. Negotiations with the parties to resolve this issue are
ongoing. The IURC ordered the fixed fuel adjustment charge remain in
place, on an interim basis, for March and April 2004.

In April 2004, the IURC issued an order that extended the interim fuel
factor for May through September 2004, subject to true-up to actual fuel
costs following the resolution of issues in the corporate separation
agreement. The IURC also issued an order that reopened the corporate
separation docket to investigate issues related to the corporate
separation agreement. On July 15, 2004, we filed a fuel factor for the
period October 2004 through March 2005. If the IURC reinstates a fixed
fuel adjustment factor, capping the fuel revenues, results of operations
and cash flows would be adversely affected if fuel costs are
under-recovered.

Michigan 2004 Fuel Recovery Plan - Affecting I&M
------------------------------------------------

A 1999 Michigan Public Service Commission's (MPSC) 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. As required, I&M
filed its 2004 PSCR Plan with the MPSC on September 30, 2003 seeking new
fuel and power supply recovery factors to be effective in 2004. A public
hearing occurred on March 10, 2004 and a MPSC order is expected during
the second half of 2004. One June 4, 2004, an ALJ recommended that SO2
and NOx costs be excluded. I&M filed exception on June 18, 2004. As
allowed by Michigan law, the proposed factors were effective on January
1, 2004, subject to review and possible adjustment based on the results
of the MPSC order.

4.  CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
    ------------------------------------------

As discussed in the 2003 Annual Report, certain AEP subsidiaries are
affected by customer choice initiatives and industry restructuring. The
Customer Choice and Industry Restructuring note in the 2003 Annual
Report should be read in conjunction with this report in order to gain a
complete understanding of material customer choice and industry
restructuring matters without significant changes since year-end. The
following paragraphs discuss significant current events related to
customer choice and industry restructuring.

OHIO RESTRUCTURING - Affecting CSPCo and OPCo
---------------------------------------------

The Ohio Electric Restructuring Act of 1999 (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
Public Utilities Commission of Ohio (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 cost-based regulated distribution and
transmission service from the incumbent utility whose distribution rates
will be approved by the PUCO and whose transmission rates will be
approved by the FERC. Retail customers will continue to have the right
to choose their electric power suppliers or receive Default Service,
which must be offered by the incumbent utility at market rates.

On December 17, 2003, the PUCO adopted a set of rules concerning the
method by which it will determine market rates for Default Service
following the MDP. The rule provides for a Market Based Standard Service
Offer (MBSSO) which would be a variable rate based on a transparent
forward market, daily market, and/or hourly market prices. The rule also
requires a fixed-rate Competitive Bidding Process (CBP) for residential
and small nonresidential customers and permits a fixed-rate CBP for
large general service customers and other customer classes. Customers
who do not switch to a competitive generation provider can choose
between them MBSSO or the CBP. Customers who make no choice will be
served pursuant to the CBP. CSPCo and OPCo were granted a waiver from
making the required MBSSO/CBP filing, as a result of their rate
stabilization plan filing.

The PUCO invited default service providers to propose an alternative to
all customers moving to market prices on January 1, 2006. On February 9,
2004, CSPCo and OPCo filed their rate stabilization plan with the PUCO
addressing prices following the end of the MDP. If approved by the PUCO,
prices would be established pursuant to the plan for the period from
January 1, 2006 through December 31, 2008. The plan is intended to
provide price stability and certainty for customers, facilitate the
development of a competitive retail market in Ohio, provide recovery of
environmental and other costs during the plan period and improve the
environmental performance of AEP's generation resources that serve Ohio
customers. The plan includes annual, fixed increases in the generation
component of all customers' bills (3% annually for CSPCo and 7% annually
for OPCo), and the opportunity for additional generation-related
increases upon PUCO review and approval. For residential customers,
however, if the temporary 5% generation rate discount provided by the
Ohio Act was eliminated prior to December 31, 2005 as permitted by the
Ohio Act, the fixed increases would be 1.6% for CSPCo and 5.7% for OPCo.
Any additional generation-related increases under the plan would be
subject to caps. The plan would maintain distribution rates through the
end of 2008 for CSPCo and OPCo at the level effective on December 31,
2005. Such rates could be adjusted for specified reasons. Transmission
charges can be adjusted to reflect applicable charges approved by the
FERC related to open access transmission, net congestion, and ancillary
services. The plan also provides for continued recovery of transition
regulatory assets and deferral of regulatory assets in 2004 and 2005 for
RTO costs and carrying charges on governmentally mandated, mainly
environmental, capital expenditures. Hearings were held in June 2004.
Briefings were completed in July and the cases are pending before the
PUCO. Management cannot predict whether the plan will be approved as
submitted or its impact on results of operations and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000,
CSPCo and OPCo are deferring customer choice implementation costs and
related carrying costs that are in excess of $20 million per company.
The agreements provide for the deferral of these costs as a regulatory
asset until the company's next distribution base rate case. Through
June 30, 2004, CSPCo incurred $35 million and deferred $15 million and
OPCo incurred $37 million and deferred $17 million of such costs. Recovery
of these regulatory assets will be subject to PUCO review in each
company's future Ohio filings for new distribution rates. If the
rate stabilization plan is approved, it would defer recovery of these
amounts until after the end of the rate stabilization period. Management
believes that the customer choice implementation costs were prudently
incurred and the deferred amounts should be recoverable in future rates.
If the PUCO determines that any of the deferred costs are unrecoverable,
it would have an adverse impact on future results of operations and cash
flows.

TEXAS RESTRUCTURING - Affecting SWEPCo, TCC and TNC
---------------------------------------------------

Texas Legislation enacted in 1999 provides the framework and timetable
to allow retail electricity competition for all Texas customers. On
January 1, 2002, customer choice of electricity supplier began in the
ERCOT area of Texas. Customer choice has been delayed in the SPP area of
Texas until at least January 1, 2007.

The Texas Legislation, among other things:
 o  provides for the recovery of regulatory assets and other stranded costs
    through securitization and non-bypassable wires charges;
 o  requires each utility to structurally unbundle into a retail electric
    provider, a power generation company and a transmission and distribution
    (T&D) utility;
 o  provides for an earnings test for each of the years 1999 through 2001 and;
 o  provides for a 2004 true-up proceeding.

The Texas Legislation required vertically integrated utilities to
legally separate their generation and retail-related assets from their
transmission and distribution-related assets. Prior to 2002, TCC and TNC
functionally separated their operations to comply with the Texas
Legislation requirements. AEP formed new subsidiaries to act as
affiliated REPs for TCC and TNC effective January 1, 2002 (the start
date of retail competition). In December 2002, AEP sold the affiliated
REPs to an unaffiliated company.

TEXAS 2004 TRUE-UP PROCEEDINGS
------------------------------

The 2004 true-up proceedings will determine the amount and recovery of:
 o  net stranded generation plant costs and generation-related regulatory assets
    (stranded plant costs),
 o  carrying charges on stranded plant costs from January 2002 (the commencement
    date of retail competition),
 o  a true-up of actual market prices determined through legislatively-mandated
    capacity auctions to the power costs used in the PUCT's excess cost over
    market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up),
 o  final approved deferred fuel balance,
 o  unrefunded accumulated excess earnings,
 o  excess of price-to-beat revenues over market prices subject to certain
    conditions and limitations (retail clawback) and
 o  other restructuring true-up items.

The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up
proceedings scheduling TCC's filing in September 2004 or 60 days after
the completion of the sale of TCC's generation assets, if later. TNC
filed its 2004 true-up proceeding in June 2004.


Summary of TCC True-up Items:
-----------------------------

                                                           Amount Recorded
                                                           at June 30, 2004
                                                           ----------------
                                                            (in millions)
Stranded Generation Plant Costs                                $1,074  (a)
Unsecuritized Transition Regulatory Asset                         194  (a)
Unrefunded Excess Earnings                                        (19) (b)
Other                                                             (46)
                                                               -------
  Amount Subject to Future Securitization                       1,203
                                                               -------
Wholesale Capacity Auction True-up                                480  (c)
Retail Clawback                                                   (30) (d)
Deferred Over-recovered Fuel                                     (210) (e)
                                                               -------
  Other Recoverable Amounts                                       240
                                                               -------
Total Recorded 2004 True-up Balance                            $1,443  (f)
                                                               =======

(a) See "Stranded Costs and Generation-Related Regulatory Assets" section
    below for additional information on this item.
(b) See "Unrefunded Excess Earnings" section below for additional information
    on this item.
(c) See "Wholesale Capacity Auction True-up" section below for additional
    information on this item.
(d) See "Retail Clawback" section below for additional information on this
    item.
(e) See "Fuel Balance Recoveries" section below for additional information on
    this item.
(f) See "Stranded Cost Recovery" section below for summary of this balance.

Stranded Costs and Generation-Related Regulatory Assets
-------------------------------------------------------

Restructuring legislation required utilities with stranded costs to use
market-based methods to value certain generation assets for determining
stranded costs. TCC is the only AEP subsidiary that has stranded costs
under the Texas Legislation. TCC elected to use the sale of assets
method to determine the market value of TCC's generation assets for
stranded cost purposes. For purposes of the 2004 true-up proceeding, the
amount of stranded costs under this market valuation methodology will be
the amount by which the book value of TCC's generation 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. Based on the prices established by the
sales, discussed below, TCC's stranded costs from the sale of generation
assets and remaining generation-related net regulatory assets are
estimated to be $1.3 billion ($1,074 million and $194 million, described
later in this section) before accrual of any applicable carrying
charges.

In June 2003, TCC began actively seeking buyers for 4,497 megawatts of
TCC's generating capacity in Texas with a net book value of $1.9 billion
at June 30, 2004. We received bids for all of TCC's generation plants.
In January 2004, TCC agreed to sell its 7.81% ownership interest in the
Oklaunion Power Station to an unaffiliated third party for approximately
$43 million. In March 2004, TCC agreed to sell its 25.2% ownership
interest in STP for approximately $333 million and its other coal, gas
and hydro plants for approximately $430 million to unaffiliated
entities. Each sale is subject to specified price adjustments. TCC sent
right of first refusal notices to the co-owners of Oklaunion and STP.
TCC filed for FERC approval of the sales of Oklaunion and the fossil and
hydro plants. TCC received a notice from a co-owner of Oklaunion and STP
exercising their right of first refusal; therefore, SEC approval will be
required. The original unaffiliated third party purchaser of Oklaunion
has petitioned for a court order declaring its contract valid and that
the co-owners' rights of first refusal are void. Approval of the sale of
STP from the Nuclear Regulatory Commission is required. On July 1, 2004,
we completed the sale of the other coal, gas and hydro plants for
approximately $425 million, net of adjustments. The completion of the
sales of STP and Oklaunion plants is expected to occur in 2004, subject
to rights of first refusal and the necessary regulatory approvals. In
order to sell these assets, TCC defeased all of its remaining
outstanding first mortgage bonds in May 2004. TCC will file its 2004
true-up proceeding with the PUCT after the completion of the sale of the
generation assets.

After the 2004 true-up proceeding, TCC may recover stranded costs and
other true-up amounts through distribution rates as a competition
transition charge and may seek to issue securitization revenue bonds for
its stranded plant costs and remaining generation net regulatory assets.
The cost of the securitization bonds is recovered through distribution
rates as a separate transition charge. TCC recognized an impairment of
its generation assets in December 2003 as a regulatory asset. At June
30, 2004, this regulatory asset was approximately $1,074 million. The
recovery of this regulatory asset and the remaining $194 million of
generation-related net regulatory assets will be subject to review and
approval by the PUCT as a stranded plant cost in the 2004 true-up
proceeding.

Carrying Charges On Recoverable Stranded Costs
----------------------------------------------

In December 2001, the PUCT issued a rule concerning stranded cost
true-up proceedings stating, among other things, that carrying costs on
stranded costs would begin to accrue on the date that the PUCT issued
its final order in the 2004 true-up proceeding. TCC and one other Texas
electric utility company filed a direct appeal of the rule to the Texas
Third Court of Appeals contending that carrying costs should commence on
January 1, 2002, the day that retail customer choice began in ERCOT.

The Third Court of Appeals ruled against the companies, who then
appealed to the Texas Supreme Court. On June 18, 2004, the Texas Supreme
Court reversed the decision of the Third Court of Appeals determining
that a carrying cost should be accrued beginning January 1, 2002 and
remanded the proceeding to the PUCT for further consideration. The
Supreme Court determined that utilities with stranded costs are not
permitted to over-recover stranded costs and the PUCT should address
whether the 2002 and 2003 wholesale capacity auction true-up regulatory
asset includes a recovery of stranded costs. Industrial intervenors have
filed a motion for rehearing with the Supreme Court which has not been
decided.

The PUCT has indicated that it will consider the Supreme Court's
decision in hearings to be held for another utility in September 2004.
The decision in that proceeding could have an impact on TCC. Since the
impact of these future PUCT proceedings cannot be determined at this
time, TCC has not recorded the carrying charge as a regulatory asset
through June 30, 2004.

Wholesale Capacity Auction True-up
----------------------------------

Texas Legislation required that electric utilities and their affiliated
power generation companies (PGC) offer for sale at auction, in 2002 and
2003 and after, at least 15% of the PGC's Texas jurisdictional installed
generation capacity in order to promote competitiveness in the wholesale
market through increased availability of generation. Actual market power
prices received in the state-mandated auctions will be used to calculate
the wholesale capacity auction true-up adjustment for TCC for the 2004
true-up proceeding. According to PUCT rules, the wholesale capacity
auction true-up is only applicable to the years 2002 and 2003. TCC
recorded a $480 million regulatory asset and related revenues which
represent the quantifiable amount of the wholesale capacity auction
true-up for the years 2002 and 2003.

In the fourth quarter of 2003, the PUCT approved a true-up filing
package containing calculation instructions similar to the methodology
employed by TCC to calculate the amount recorded for recovery under its
wholesale capacity auction true-up. The PUCT will review the $480
million wholesale capacity auction true-up regulatory asset for recovery
as part of the 2004 true-up proceeding.

Fuel Balance Recoveries
-----------------------

In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail
sales within its ERCOT service area for inclusion in the 2004 true-up
proceeding. In January 2004, the PUCT announced a final ruling in TNC's
fuel reconciliation case. The PUCT issued a written order in March 2004
that established TNC's unrecovered fuel balance for the ERCOT service
territory. Various parties, including TNC, requested rehearing of the
PUCT's order. In May 2004, the PUCT reversed certain prior rulings
resulting in TNC having a final fuel over-recovery balance of
approximately $7 million. TNC's 2004 true-up proceeding, filed in June
2004, will be updated to reflect the balance after the PUCT issues a
final fuel order. TNC has provided for all to-date disallowances pending
receipt of the final order. Management is unable to predict the amount
of TNC's fuel over-recovery which will be included in its 2004 true-up
proceedings.

In 2002, TCC filed with the PUCT to reconcile fuel costs and to
establish its deferred over-recovery of fuel balance for inclusion in
the 2004 true-up proceeding. In May 2004, the PUCT remanded TCC's fuel
proceeding to the ALJ. TCC has provided $210 million for its
over-recovery balance at June 30, 2004. TCC has provided for all to-date
disallowances pending receipt of a final order. Management is unable to
predict the amount of TCC's fuel over-recovery which will be included in
its 2004 true-up proceeding.

See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 3 "Rate
Matters" for further discussion.

Unrefunded Excess Earnings
--------------------------

The Texas Legislation provides for the calculation of excess earnings
for each year from 1999 through 2001. The total excess earnings
determined for the three-year period were $3 million for SWEPCo, $47
million for TCC and $19 million for TNC. TCC, TNC and SWEPCo challenged
the PUCT's treatment of fuel-related deferred income taxes and appealed
the PUCT's final 2000 excess earnings to the Travis County District
Court which upheld the PUCT ruling. The District Court's ruling was
appealed to the Third Court of Appeals. In August 2003, the Third Court
of Appeals reversed the PUCT order and the District Court judgment. The
PUCT's request for rehearing of the Appeals Court's decision was denied
and the PUCT chose not to appeal the ruling any further. The District
Court remanded to the PUCT an appeal of the same issue from the PUCT's
2001 order to be consistent with the Court of Appeals decision. Since an
expense and regulatory liability had been accrued in prior years in
compliance with the PUCT orders, the companies reversed a portion of
their regulatory liability for the years 2000 and 2001 consistent with
the Appeals Court's decision and credited amortization expense during
the third quarter of 2003.

In 2001, the PUCT issued an order requiring TCC to return estimated
excess earnings by reducing distribution rates by approximately $55
million plus accrued interest over a five-year period beginning January
1, 2002. Since excess earnings amounts were expensed in 1999, 2000 and
2001, the order has no additional effect on reported net income but will
reduce cash flows for the five-year refund period. The amount to be
refunded is recorded as a regulatory liability ($19 million at June 30,
2004). Management believes that TCC will have stranded costs and that it
was inappropriate for the PUCT to order a refund prior to TCC's 2004
true-up proceeding. TCC appealed the PUCT's refund of excess earnings to
the Travis County District Court. That court affirmed the PUCT's
decision and further ordered that the refunds be provided to ultimate
customers. TCC has appealed the decision to the Court of Appeals.

Retail Clawback
---------------

The Texas Legislation provides for the affiliated price-to-beat (PTB)
retail electric providers (REP) serving residential and small commercial
customers to refund to its T&D utility the excess of the PTB revenues
over market prices (subject to certain conditions and a limitation of
$150 per customer). This is the retail clawback. If, prior to January 1,
2004, 40% of the load for the residential or small commercial classes is
served by competitive REPs, the retail clawback is not applicable for
that class of customer. During 2003, TCC and TNC filed to notify the
PUCT that competitive REPs serve over 40% of the load in the small
commercial class. The PUCT approved TCC's and TNC's filings in December
2003. In 2002, AEP had accrued a regulatory liability of approximately
$9 million for the small commercial retail clawback on its REP's books.
When the PUCT certified that the REP's in TCC and TNC service
territories had reached the 40% threshold, the regulatory liability was
no longer required for the small commercial class and was reversed in
December 2003. Based upon customer information filed by the unaffiliated
company which operates as the affiliated REP for TCC and TNC, we updated
the estimated retail clawback regulatory liability in May 2004. At June
30, 2004, the retail clawback regulatory liability was $30 million for
TCC and $7 million for TNC.

TNC 2004 True-up Filing
-----------------------

In June 2004, TNC filed its 2004 true-up proceeding including the fuel
reconciliation balance and the retail clawback calculation. The amount
of deferred fuel, an over-recovery balance of $7 million at June 30, 2004,
remains under review by the PUCT and is subject to possible revision.
The retail clawback regulatory liability was adjusted in the second
quarter of 2004 to $7 million (TNC's allocated portion of the REP's
retail clawback) reflecting the number of customers served on January 1,
2004. The PUCT has deferred this proceeding pending the resolution of
the final fuel proceeding.

Stranded Cost Recovery
----------------------

When the 2004 true-up proceeding is completed, TCC intends to file to
recover PUCT-approved stranded costs and other true-up amounts that are
in excess of current securitized amounts, plus appropriate carrying
charges, through non-bypassable competition transition charge in the
regulated T&D rates. TCC may also seek to securitize the approved stranded
plant costs and generation-related net regulatory assets that were not
previously recovered through a prior securitization and the
non-bypassable transition charge. The annual costs of securitization are
recovered through the non-bypassable transition charge collected by the
T&D utility over the term of the securitization bonds.

TCC's recorded net regulatory asset for amounts subject to approval in the 2004
true-up proceeding is approximately $1.4 billion. Management estimates
that TCC's 2004 true-up filing will exceed the total of its recorded net
regulatory asset. Management expects that the 2004 true-up proceeding
will be contentious and could possibly result in disallowances.

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

VIRGINIA RESTRUCTURING - Affecting APCo
---------------------------------------

In April 2004, the Governor of Virginia signed legislation which extends
the transition period for electricity restructuring, including capped
rates, through December 31, 2010. The legislation provides specific cost
recovery opportunities during the capped rate period, including two
optional general based rate changes and an opportunity for recovery,
through a separate rate mechanism, of incremental environmental and
reliability costs.

5.  COMMITMENTS AND CONTINGENCIES
    -----------------------------

As discussed in the Commitments and Contingencies note within the 2003
Annual Report, certain AEP subsidiaries continue to be involved in
various legal matters. The 2003 Annual Report should be read in
conjunction with this report in order to understand the other material
nuclear and operational matters without significant changes since their
disclosure in the 2003 Annual Report. The material matters discussed in
the 2003 Annual Report without significant changes in status since
year-end include, but are not limited to, (1) nuclear matters, (2)
construction commitments, (3) potential uninsured losses, (4) merger
litigation, and (5) FERC proposed Standard Market Design. See disclosure
below for significant matters with changes in status subsequent to the
disclosure made in the 2003 Annual Report.

ENVIRONMENTAL
-------------

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

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

Under the CAA, if a plant undertakes a major modification that directly
results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution
control technology. This requirement does not apply to activities such
as routine maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and efficient
operation of the plant. The CAA 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 June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in
order to "perfect" its complaint in the pending litigation. The NOV
expands the number of alleged "modifications" undertaken at the
Muskingum River, Cardinal, Conesville and Tanners Creek plants during
scheduled outages on these units from 1979 through the present.
Approximately one-third of the allegations in the NOV are already
contained in allegations made by the states or the special interest
groups in the pending litigation. The Federal EPA is expected to file a
motion to amend its complaint, and, to the extent that motion seeks to
expand the scope of the pending litigation, the AEP subsidiaries will
oppose that motion.

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 was scheduled for July 2004, but has been
postponed until January 2005 to facilitate further settlement
negotiations.

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 the Federal EPA
bears the burden of proof on the issue of whether a practice is "routine
maintenance, repair, or replacement" and on whether or not a
"significant net emissions increase" results from a physical change or
change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the
relevant source category" in determining if it is "routine." Further,
the Federal EPA must calculate emissions by determining first whether a
change in the maximum achievable hourly emission rate occurred as a
result of the change, and then must calculate any change in annual
emissions holding hours of operation constant before and after the
change. The Federal EPA requested reconsideration of this decision, or
in the alternative, certification of an interlocutory appeal to the
Fourth Circuit Court of Appeals, and the District Court denied the
Federal EPA's motion. On April 13, 2004, the parties filed a joint
motion for entry of final judgment, based on stipulations of relevant
facts that obviated the need for a trial, but preserving plaintiffs'
right to seek an appeal of the federal prevention of significant
deterioration (PSD) claims. On April 14, 2004, the Court entered final
judgment for Duke Energy on all of the PSD claims made in the amended
complaints, and dismissed all remaining claims with prejudice. The
United States subsequently filed a notice of appeal to the Fourth
Circuit Court of Appeals, which issued a briefing order requiring the
case to be fully briefed by late September 2004.

On June 24, 2003, the United States Court of Appeals for the 11th
Circuit issued an order invalidating the administrative compliance order
issued by the Federal EPA to the Tennessee Valley Authority for alleged
CAA 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 CAA are unconstitutional. The United States filed a petition for
certiorari with the United States Supreme Court and on May 3, 2004, that
petition was denied.

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 a prospective effect, and was to become effective in
certain states 60 days after October 27, 2003, the date of its
publication in the Federal Register, and in other states upon completion
of state processes to incorporate the new rule into state law. On
October 27, 2003 twelve states, the District of Columbia and several
cities filed an action in the United States Court of Appeals for the
District of Columbia Circuit seeking judicial review of the new rule.
The UARG has intervened in this case. On December 24, 2003, the Circuit
Court granted a motion from the petitioners to stay the effective date
of this rule, which had been December 26, 2003.

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

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

On July 21, 2004, the Sierra Club issued a notice of intent to file a
citizen suit claim against DPL, Inc., Cinergy Corporation, CSPCo, and
The Dayton Power & Light Company for alleged violations of the New
Source Review programs at the Stuart Station. CSPCo owns a 26% share of
the Stuart Station. Management is unable to predict the timing of any
future action by the special interest group or the effect of such
actions on future operations or cash flows.

SWEPCo Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo
--------------------------------------------------------------------------

On July 13, 2004, two special interest groups issued a notice of intent
to commence a citizen suit under the Clean Air Act for alleged
violations of various permit conditions in permits issued to SWEPCo's
Welsh, Knox Lee, and Pirkey plants. This notice was prompted by allegations
made by a terminated AEP employee. The allegations at the Welsh Plant
concern compliance with emission limitations on particulate matter and
carbon monoxide, compliance with a referenced design heat input valve,
and compliance with certain reporting requirements. The allegations at
the Knox Lee Plant relate to the receipt of an off-specification fuel
oil, and the allegations at Pirkey Plant relate to testing and reporting
of volatile organic compound emissions. No action can be commenced until
60 days after the date of notice.

On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ)
issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant
containing a summary of findings resulting from a compliance
investigation at the plant. The summary includes allegations concerning
compliance with certain recordkeeping and reporting requirements,
compliance with a referenced design heat input valve in the Welsh
permit, compliance with a fuel sulfur content limit, and compliance with
emission limits for sulfur dioxide.

SWEPCo has previously reported to the TCEQ, deviations related to the
receipt of off-specification fuel at Knox Lee, and the referenced
recordkeeping and reporting requirements and heat input valve at Welsh.
SWEPCo is preparing additional responses to the Notice of Enforcement
and the notice from the special interest groups. Management is unable to
predict the timing of any future action by TCEQ or the special interest
groups or the effect of such actions on results of operations, financial
condition or cash flows.

Carbon Dioxide Public Nuisance Claims  - Affecting AEP System
-------------------------------------------------------------

On July 21, 2004, attorneys general from eight states and the
corporation counsel for the City of New York filed an action in federal
district court for the Southern District of New York against AEP, AEPSC
and four other unaffiliated governmental and investor-owned electric
utility systems. That same day, a similar complaint was filed in the
same court against the same defendants by the Natural Resources Defense
Council on behalf of two special interest groups. The actions allege
that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts
associated with global warming, and seek injunctive relief in the form
of specific emission reduction commitments from the defendants.
Management believes the actions are without merit and intends to
vigorously defend against the claims.

Nuclear Decommissioning - Affecting TCC
---------------------------------------

As discussed in the 2003 Annual Report, decommissioning costs are
accrued over the service life of STP. The licenses to operate the two
nuclear units at STP expire in 2027 and 2028. TCC had estimated its
portion of the costs of decommissioning STP to be $289 million in 1999
nondiscounted dollars. TCC is accruing and recovering these
decommissioning costs through rates based on the service life of STP at
a rate of approximately $8 million per year.

In May 2004, an updated decommissioning study was completed for STP. The
study estimates TCC's share of the decommissioning costs of STP to be
$344 million in nondiscounted 2004 dollars. As discussed in Note 7, TCC
is in the process of selling its ownership interest in STP to a
non-affiliate, and upon completion of the sale it is anticipated that
TCC will no longer be obligated for nuclear decommissioning liabilities
associated with STP.

OPERATIONAL
-----------

Power Generation Facility - Affecting OPCo
------------------------------------------

AEP has agreements with Juniper Capital L.P. (Juniper) under which
Juniper constructed and financed a non-regulated merchant power
generation facility (Facility) near Plaquemine, Louisiana and leased the
Facility to AEP. AEP has subleased the Facility to the Dow Chemical
Company (Dow). The Facility is a Dow-operated "qualifying cogeneration
facility" for purposes of PURPA. Commercial operation of the Facility as
required by the agreements between Juniper, AEP and Dow was achieved on
March 18, 2004.

Dow uses a portion of the energy produced by the Facility and sells the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of
such excess energy from Dow. Because the Facility is a major steam
supply for Dow, Dow is expected to operate the Facility at certain
minimum levels, and OPCo is obligated to purchase the energy generated
at those minimum operating levels (expected to be approximately 270 MW).

OPCo has also agreed to sell up to approximately 800 MW of energy to
Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a
Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a
price that is currently in excess of market. OPCo has entered an
agreement with an affiliate that eliminates OPCo's market exposure
related to the PPA. AEP has guaranteed this affiliate's performance
under the agreement. Beginning May 1, 2003, OPCo tendered replacement
capacity, energy and ancillary services to TEM pursuant to the PPA which
TEM rejected as non-conforming. Commercial operation for purposes of the
PPA began April 2, 2004.

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

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

On March 26, 2004, OPCo requested that TEM provide assurances of
performance of its future obligations under the PPA, but TEM refused to
do so. As indicated above, OPCo also gave notice to TEM and declared
April 2, 2004 as the "Commercial Operations Date." Despite OPCo's prior
tenders of replacement electric power products to TEM beginning May 1,
2003 and despite OPCo's tender of electric power products from the
Facility to TEM beginning April 2, 2004, TEM refused to accept and pay
for them under the terms of the PPA. On April 5, 2004, OPCo gave notice
to TEM that OPCo (i) was suspending performance of its obligations under
PPA, (ii) would be seeking a declaration from the New York federal court
that the PPA has been terminated and (iii) would be pursuing against TEM
and Tractebel SA under the guaranty damages and the full termination
payment value of the PPA.

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

In 2002, certain subsidiaries of AEP filed claims against Enron and its
subsidiaries in the Enron bankruptcy proceeding pending in the U.S.
Bankruptcy Court for the Southern District of New York. At the date of
Enron's bankruptcy, certain subsidiaries of AEP had open trading
contracts and trading accounts receivables and payables with Enron. In
addition, on June 1, 2001, AEP purchased Houston Pipe Line Company (HPL)
from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.

Commodity trading settlement disputes - In September 2003, Enron filed a
complaint in the Bankruptcy Court against AEPES challenging AEP's
offsetting of receivables and payables and related collateral across
various Enron entities and seeking payment of approximately $125 million
plus interest in connection with gas-related trading transactions. The
AEP subsidiaries asserted their right to offset trading payables owed to
various Enron entities against trading receivables due to several AEP
subsidiaries. The parties are currently in non-binding court-sponsored
mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court
against AEPSC seeking approximately $93 million plus interest in
connection with a transaction for the sale and purchase of physical
power among Enron, AEP and Allegheny Energy Supply, LLC during November
2001. Enron's claim seeks to unwind the effects of the transaction. AEP
believes it has several defenses to the claims in the action being
brought by Enron. The parties are currently in non-binding
court-sponsored mediation.

Enron bankruptcy summary - The amount expensed in prior years in
connection with the Enron bankruptcy was based on an analysis of
contracts where AEP and Enron entities are counterparties, the
offsetting of receivables and payables, the application of deposits from
Enron entities and management's analysis of the HPL related purchase
contingencies and indemnifications. As noted above, Enron has challenged
the offsetting of receivables and payables. Management is unable to
predict the outcome of these lawsuits or their impact on results of
operations, cash flows and financial condition.

Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC
------------------------------------------------------------

Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider
(REP), filed a lawsuit in federal District Court in Corpus Christi,
Texas, in July 2003, against AEP and four of its subsidiaries, including
TCC and TNC, certain unaffiliated energy companies and ERCOT. The action
alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made
against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price
spikes requiring TCE to post additional collateral and ultimately forced
it into bankruptcy when it was unable to raise prices to its customers
due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary
damages and court costs. Two additional parties, Utility Choice, LLC and
Cirro Energy Corporation, have sought leave to intervene as plaintiffs
asserting similar claims. AEP and its subsidiaries filed a Motion to
Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. AEP and its subsidiaries filed a Motion to Dismiss the
amended complaint. In June 2004, the Court dismissed all claims against
the AEP companies. TCE has appealed the trial court's decision to the
United States Court of Appeals for the Fifth Circuit.

Energy Market Investigation - Affecting AEP System
--------------------------------------------------

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

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. In
January 2004, the CFTC issued a request for documents and other
information in connection with a CFTC investigation of activities
affecting the price of natural gas in the fall of 2003. We responded to
that request. The case is in the initial pleading stage with our
response to the complaint currently due on September 13, 2004. Although
management is unable to predict the outcome of this case, we recorded a
provision in 2003 and the action is not expected to have a material
effect on future results of operations, financial condition or cash
flows. Management cannot predict what, if any, further action, these
governmental agencies may take with respect to these matters.

FERC Market Power Mitigation - Affecting AEP System
---------------------------------------------------

A FERC order issued in November 2001 on AEP's triennial market based
wholesale power rate authorization update required certain mitigation
actions that AEP would need to take for sales/purchases within its
control area and required AEP to post information on its website
regarding its power system's status. As a result of a request for
rehearing filed by AEP and other market participants, FERC issued an
order delaying the effective date of the mitigation plan until after a
planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a
technical conference in January 2004. In April 2004, the FERC issued two
orders concerning utilities' ability to sell wholesale electricity at
market-based rates. In the first order, the FERC adopted two new interim
screens for assessing potential generation market power of applicants
for wholesale market based rates, and described additional analyses and
mitigation measures that could be presented if an applicant does not
pass one of these interim screens. In July 2004, the FERC issued an
order on rehearing affirming its conclusions in the April order and
directing AEP and two unaffiliated utilities to file generation market
power analyses within 30 days. In the second order, the FERC initiated a
rulemaking to consider whether the FERC's current methodology for
determining whether a public utility should be allowed to sell wholesale
electricity at market-based rates should be modified in any way.
We plan to present evidence to demonstrate that we do not possess market
power in geographic areas where we sell wholesale power.

6.  GUARANTEES
    ----------
There are no material liabilities recorded for guarantees in accordance
with FIN 45. 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.

Letter of Credit
----------------

TCC has entered into a standby letter of credit (LOC) with third
parties. This LOC covers credit enhancements for issued bonds. This LOC
was issued in TCC's ordinary course of business. At June 30, 2004, the
maximum future payments of the LOC are $43 million which matures
November 2005. There is no recourse to third parties in the event this
letter of credit is 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 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 $51 million with
maturity dates ranging from June 2005 to February 2012.

As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining, SWEPCo has agreed to provide
guarantees of mine reclamation in the amount of approximately $85
million. Since SWEPCo uses self-bonding, the guarantee provides for
SWEPCo to commit to use its resources to complete the reclamation in the
event the work is not completed by a third party miner. At June 30,
2004, the cost to reclaim the mine in 2035 is estimated to be
approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.

On July 1, 2003, SWEPCo consolidated Sabine due to the application of
FIN 46 (see Note 2). Upon consolidation, SWEPCo recorded the assets and
liabilities of Sabine ($78 million). Also, after consolidation, SWEPCo
currently records all expenses (depreciation, interest and other
operation expense) of Sabine and eliminates Sabine's revenues against
SWEPCo's fuel expenses. There is no cumulative effect of an accounting
change recorded as a result of the requirement to consolidate, and there
is no change in net income due to the consolidation of Sabine. SWEPCo
dos not have an ownership interest in Sabine.

Indemnifications and Other Guarantees
-------------------------------------

All of the registrant subsidiaries enter into certain types of
contracts, which would require indemnifications. Typically these
contracts include, but are not limited to, sale agreements, lease
agreements, purchase agreements and financing agreements. Generally
these agreements may include, but are not limited to, indemnifications
around certain tax, contractual and environmental matters. With respect
to sale agreements, exposure generally does not exceed the sale price.
Registrant subsidiaries cannot estimate the maximum potential exposure
for any of these indemnifications entered into prior to December 31,
2002 due to the uncertainty of future events. In 2003 and during the
first six months of 2004, registrant subsidiaries entered into sale
agreements which included indemnifications with a maximum exposure that
was not significant for any individual registrant subsidiary except for
TCC which entered into an indemnification of $129 million relating to
the sale of its generation assets on July 1, 2004 (see note 7). There
are no material liabilities recorded for any indemnifications.

Certain registrant subsidiaries lease certain equipment under a master
operating lease. Under the lease agreement, the lessor is guaranteed to
receive up to 87% of the unamortized balance of the equipment at the end
of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, we have
committed to pay the difference between the fair market value and the
unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At June 30, 2004, 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                                $5
                CSPCo                                2
                I&M                                  3
                KPCo                                 1
                OPCo                                 4
                PSO                                  4
                SWEPCo                               4
                TCC                                  6
                TNC                                  3

 7.  DISPOSITIONS AND ASSETS HELD FOR SALE
     -------------------------------------

Texas Plants
------------

In December 2002, TCC filed a plan of divestiture with the PUCT
proposing to sell all of its power generation assets, including the
eight gas-fired generating plants that were either deactivated or
designated as "reliability must run" status.

During the fourth quarter of 2003, after receiving bids from interested
buyers, TCC recorded a $938 million impairment loss and changed the
classification of the plant assets from plant in service to Assets Held
for Sale. In accordance with Texas legislation, the $938 million
impairment was offset by the establishment of a regulatory asset, which
is expected to be recovered through a wires charge, subject to the final
outcome of the 2004 Texas true-up proceeding. As a result of the 2004
true-up proceeding, if we are unable to recover all or a portion of our
requested costs (see Note 4), any unrecovered costs could have a
material adverse effect on our results of operations, cash flows and
possibly financial condition.

During early 2004, TCC signed agreements to sell all of its generating
assets, at prices which approximate book value after considering the
impairment charge described above. As a result, TCC does not expect
these pending asset sales, described below, to have a significant effect
on its future results of operations, except in the case that our true-up
proceedings, as described above, do not allow for recovery of our
stranded costs.

       Oklaunion Power Station
       -----------------------
       In April 2004, TCC signed an agreement to sell its 7.81 percent
       share of Oklaunion Power Station for approximately $43 million
       (subject to closing adjustments) to an unrelated party. In May
       2004, TCC received notice from co-owners of the Oklaunion Power
       Station, announcing their decision to exercise their right of
       first refusal, with terms similar to the original agreement. The
       sale is currently being challenged by the unrelated party with
       which TCC entered into the original sales agreement. The
       unrelated party alleges that the co-owner has exceeded its legal
       authority and has requested that the court declare the one
       co-owner's exercise of its right of first refusal void. The
       unrelated party further argues that the second of the two
       co-owner's exercise of its right of first refusal is not timely
       and invalid. TCC expects that it will be able to resolve this
       legal issue and that the planned sale will close by the end of
       2004.

       South Texas Project
       -------------------
       In February 2004, TCC signed an agreement to sell its 25.2
       percent share of the South Texas Project (STP) nuclear plant for
       approximately $333 million, subject to closing adjustments. In
       June 2004, TCC received notice from co-owners of their decisions
       to exercise their rights of first refusal, with terms similar to
       the original agreement. TCC expects the sale to close before the
       end of 2004 subject to necessary regulatory approval.

       TCC Generation Assets
       ---------------------
       In March 2004, TCC signed an agreement to sell its remaining
       generating assets, including eight natural gas plants, one
       coal-fired plant and one hydro plant to a non-related joint
       venture. The sale was completed in July 2004 for approximately
       $425 million, net of adjustments. The sale did not have a
       significant effect on TCC's results of operation during the
       second quarter 2004.

The assets and liabilities of the TCC plants held for sale at June 30,
2004 and December 31, 2003 are as follows:

                                      June 30, 2004      December 31, 2003
                                      -------------      -----------------
 Assets:                                        (in millions)
 ------
 Other Current Assets                      $58                    $57
 Property, Plant and Equipment, Net        796                    797
 Regulatory Assets                          51                     49
 Decommissioning Trusts                    132                    125
                                        -------                -------
 Total Assets Held for Sale             $1,037                 $1,028
                                        =======                =======

 Liabilities:
 -----------
 Regulatory Liabilities                     $9                     $9
 Asset Retirement Obligations              227                    219
                                        -------                -------
 Total Liabilities Held for Sale          $236                   $228
                                        =======                =======

8.  BENEFIT PLANS
    -------------

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in
AEP sponsored U.S. qualified pension plans and nonqualified pension
plans. A substantial majority of employees are covered by either one
qualified plan or both a qualified and a nonqualified pension plan. In
addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWPECo, TCC and TNC
participate in other postretirement benefit plans sponsored by AEP to
provide medical and death benefits for retired employees in the U.S.

The following tables provide the components of AEP's net periodic
benefit cost (credit) for the plans for the three and six months ended
June 30, 2004 and 2003:
<TABLE>
<CAPTION>
Three Months ended June 30, 2004 and 2003:
-----------------------------------------
                                                                                                         U.S.
                                                                   U.S.                          Other Postretirement
                                                              Pension Plans                         Benefit Plans
                                                         ---------------------                 ------------------------
                                                         2004             2003                 2004                2003
                                                         ----             ----                 ----                ----
                                                                                 (in millions)
 <C>                                                      <C>              <C>                  <C>                 <C>
 Service Cost                                             $21              $20                  $10                 $11
 Interest Cost                                             57               59                   30                  33
 Expected Return on Plan Assets                           (73)             (80)                 (20)                (17)
 Amortization of Transition
   (Asset) Obligation                                       1               (2)                   7                   6
 Amortization of Net Actuarial Loss                         4                3                    9                  13
                                                          ----             ----                 ----                ----
 Net Periodic Benefit Cost (Credit)                       $10               $-                  $36                 $46
                                                          ====             ====                 ====                ====

</TABLE>
<TABLE>
<CAPTION>
Six Months ended June 30, 2004 and 2003:
---------------------------------------
                                                                                                         U.S.
                                                                   U.S.                          Other Postretirement
                                                              Pension Plans                         Benefit Plans
                                                         ---------------------                 ------------------------
                                                         2004             2003                 2004                2003
                                                         ----             ----                 ----                ----
                                                                                 (in millions)
 <C>                                                      <C>              <C>                  <C>                 <C>
 Service Cost                                             $43              $40                  $20                 $21
 Interest Cost                                            114              117                   59                  65
 Expected Return on Plan Assets                          (146)            (159)                 (41)                (32)
 Amortization of Transition
   (Asset) Obligation                                       1               (4)                  14                  14
 Amortization of Net Actuarial Loss                         8                5                   18                  26
                                                          ----            -----                 ----                ----
 Net Periodic Benefit Cost (Credit)                       $20              $(1)                 $70                 $94
                                                          ====            =====                 ====                ====
</TABLE>

 The following table provides the net periodic benefit cost (credit) for
 the plans by the following AEP registrant subsidiaries for the three and
 six months ended June 30, 2004 and 2003:

Three Months ended June 30, 2004 and 2003:
-----------------------------------------

                           U.S.                            U.S. Other
                      Pension Plans              Postretirement Benefit Plans
                    -----------------            ----------------------------
                    2004         2003                 2004          2003
                    ----         ----                 ----          ----
                                      (in thousands)
 APCo               $313      $(1,299)               $6,430       $8,371
 CSPCo              (409)      (1,350)                2,763        3,671
 I&M               1,112         (201)                4,315        5,749
 KPCo                143         (140)                  741        1,011
 OPCo                (34)      (1,656)                4,907        7,036
 PSO                 684          (72)                2,112        2,471
 SWEPCo              888          254                 2,100        2,566
 TCC                 728          (32)                2,536        3,237
 TNC                 332          153                 1,070        1,469


Six Months ended June 30, 2004 and 2003:
---------------------------------------
                           U.S.                            U.S. Other
                      Pension Plans              Postretirement Benefit Plans
                    -----------------            ----------------------------
                    2004         2003                 2004          2003
                    ----         ----                 ----          ----
                                      (in thousands)
 APCo               $635      $(2,600)              $12,860      $16,809
 CSPCo              (813)      (2,700)                5,525        7,342
 I&M               2,230         (404)                8,630       11,499
 KPCo                287         (282)                1,481        2,021
 OPCo                (62)      (3,312)                9,813       14,072
 PSO               1,397         (146)                4,224        4,942
 SWEPCo            1,802          508                 4,200        5,132
 TCC               1,494          (62)                5,072        6,475
 TNC                 676          304                 2,140        2,937

9.  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.

10.  FINANCING ACTIVITIES
     --------------------

Long-term debt and other securities issued and retired during the first
six months of 2004 were:

<TABLE>
<CAPTION>

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

<C>                         <C>                                          <C>                  <C>                  <C>
Issuances:
---------
CSPCo                       Installment Purchase Contracts               $43,695              Variable             2038
OPCo                        Financing Obligation                           6,080                5.77               2024
PSO                         Installment Purchase Contracts                33,700              Variable             2014
PSO                         Senior Unsecured Notes                        50,000                4.70               2009
SWEPCo                      Installment Purchase Contracts                53,500              Variable             2019
SWEPCo                      Installment Purchase Contracts                41,135              Variable             2011
SWEPCo                      Financing Obligation                          14,226                5.77               2024

</TABLE>
<TABLE>
<CAPTION>

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

<C>                         <C>                                          <C>                  <C>                  <C>
APCo                        First Mortgage Bonds                          45,000                7.125              2024
APCo                        Installment Purchase Contracts                40,000                5.45               2019
CSPCo                       First Mortgage Bonds                          11,000                7.60               2024
CSPCo                       Installment Purchase Contracts                43,695                6.25               2020
I&M                         First Mortgage Bonds                          30,000                7.20               2024
I&M                         First Mortgage Bonds                          25,000                7.50               2024
OPCo                        Installment Purchase Contracts                50,000                6.85               2022
OPCo                        Notes Payable                                  1,500                6.27               2009
OPCo                        Notes Payable                                  2,927                6.81               2008
OPCo                        First Mortgage Bonds                          10,000                7.30               2024
OPCo                        Senior Unsecured Notes                       140,000                7.375              2038
PSO                         Notes Payable to Trust                        77,320                8.00               2037
PSO                         Installment Purchase Contracts                33,700                4.875              2014
SWEPCo                      Installment Purchase Contracts                53,500                7.60               2019
SWEPCo                      Installment Purchase Contracts                12,290                6.90               2004
SWEPCo                      Installment Purchase Contracts                12,170                6.00               2008
SWEPCo                      Installment Purchase Contracts                17,125                8.20               2011
SWEPCo                      First Mortgage Bonds                          80,000                6.875              2025
SWEPCo                      First Mortgage Bonds                          40,000                7.75               2004
SWEPCo                      Notes Payable                                  3,415                4.47               2011
SWEPCo                      Notes Payable                                  1,500              Variable             2008
TCC                         First Mortgage Bonds                           6,195                6.625              2005
TCC                         Securitization Bonds                          28,809                3.54               2005
TNC                         First Mortgage Bonds                          24,036                6.125              2004
</TABLE>

<TABLE>
<CAPTION>


                                                                       Principal              Interest
Company                          Type of Debt                           Amount                  Rate              Due Date
-------                          ------------                          ---------              --------            --------
                                                                     (in thousands)             (%)
Defeasance:
----------
<C>                         <C>                                          <C>                  <C>                  <C>
TCC                         First Mortgage Bonds                         $27,400 (a)           7.25                2004
TCC                         First Mortgage Bonds                          65,763 (a)           6.625               2005
TCC                         First Mortgage Bonds                          18,581 (a)           7.125               2008
</TABLE>


(a) Trust fund assets for defeasance of First Mortgage Bonds of $103
million are included in Other Cash Deposits and $22 million in Bond
Defeasance Funds in TCC's Consolidated Balance Sheets at June 30, 2004.
Trust fund assets are restricted for exclusive use in retiring the First
Mortgage Bonds.

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

<TABLE>
<CAPTION>

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

<C>                         <C>                                          <C>                  <C>                  <C>
KPCo                        Notes Payable                                $20,000              5.25                 2015
OPCo                        Notes Payable                                200,000              5.25                 2015

Retirements:
-----------

  None.

</TABLE>

Lines of Credit - AEP System
----------------------------

The AEP System uses a corporate borrowing program to meet the short-term
borrowing needs of its subsidiaries. The corporate borrowing program
includes a utility money pool, which funds the utility subsidiaries and
a non-utility money pool, which funds the majority of the non-utility
subsidiaries. In addition, the AEP System also funds, as direct
borrowers, the short-term debt requirements of other subsidiaries that
are not participants in the non-utility money pool for regulatory or
operational reasons. The AEP System Corporate Borrowing Program operates
in accordance with the terms and conditions outlined by the SEC. AEP has
authority from the SEC through March 31, 2006 for short-term borrowings
sufficient to fund the utility money pool and the non-utility money pool
as well as its own requirements in an amount not to exceed $7.2 billion.
Utility money pool participants include AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC (domestic utility companies). Our
previous order grating borrowing authority to our utilities listed below
expired on June 30 2004. Through June 30, 2004, we had not exceeded our
authority under the previous order. The following are the SEC authorized
limits for short-term borrowings for the domestic utility companies as
of July 1, 2004:

                                                         Authorized
                                                         ----------
                                                        (in millions)

    AEP Generating Company                                  $125
    AEP Texas Central Company                                600
    AEP Texas North Company                                  250
    Appalachian Power Company                                600
    Columbus Southern Power Company                          150
    Indiana Michigan Power Company                           500
    Kentucky Power Company                                   200
    Ohio Power Company                                       600
    Public Service Company of Oklahoma                       300
    Southwestern Electric Power Company                      350

<PAGE>

     REGISTRANT SUBSIDIARIES' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
     ----------------------------------------------------------------------

The following is a combined presentation of certain components of the
registrant subsidiaries' management's discussion and analysis. The
information in this section completes the information necessary for
management's discussion and analysis of financial condition and results
of operations and is meant to be read with (i) Management's Financial
Discussion and Analysis, (ii) financial statements, and (iii) footnotes
of each individual registrant. The Registrants' Combined Management's
Discussion and Analysis section of the 2003 Annual Report should be read
in conjunction with this report.

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

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

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

The status of the transfer of functional control of our subsidiaries'
transmission systems to RTOs or the status of our participation in RTOs
has not changed significantly from our disclosure as described in "RTO
Formation" within the "Registrants' Combined Management's Discussion and
Analysis" section of the 2003 Annual Report.

In November 2003, the FERC preliminarily found that certain AEP
subsidiaries must fulfill their CSW merger condition to join an RTO by
integrating into PJM (transmission and markets) by October 1, 2004. FERC
based their order on PURPA 205(a), which allows FERC to exempt electric
utilities from state law or regulation in certain circumstances. An ALJ
held hearings on issues including whether the laws, rules, or
regulations of Virginia and Kentucky prevent AEP subsidiaries from
joining an RTO and whether the exceptions under PURPA 205(a) apply. The
FERC ALJ affirmed the FERC's preliminary findings in March 2004. The
FERC issued a final order in June 2004.

In April 2004, KPCo reached an agreement with interveners to settle the
RTO issues in Kentucky. The KPSC approved the settlement agreement in
May 2004 and the FERC approved the settlement in June 2004.

In July 2004, APCo reached an agreement with the intervenors to settle
the RTO issues in Virginia. The settlement agreement is now subject to
approval by the Virginia SCC.

If the Virginia settlement is approved, it should allow the AEP East
companies to join PJM and address state concerns without any significant
expected adverse impacts on future results of operations.

AEP West companies are members of ERCOT or SPP. In February 2004, the
FERC granted RTO status to the SPP, subject to fulfilling specified
requirements. Regulatory activities concerning various RTO issues are
ongoing in Arkansas and Louisiana.

Litigation
----------

AEP subsidiaries continue to be involved in various litigation matters
as described in the "Significant Factors - Litigation" section of
Registrants' Combined Management's Discussion and Analysis in the 2003
Annual Report. The 2003 Annual Report should be read in conjunction with
this report in order to understand other litigation matters that did not
have significant changes in status since the issuance of the 2003 Annual
Report, but may have a material impact on future results of operations,
cash flows and financial condition. Other matters described in the 2003
Annual Report that did not have significant changes during the first six
months of 2004, that should be read in order to gain a full
understanding of the current litigation include disclosure related to
Potential Uninsured Losses.

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

See discussion of New Source Review Litigation under "Environmental Matters".

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

In 2002, certain subsidiaries of AEP filed claims against Enron and its
subsidiaries in the Enron bankruptcy proceeding pending in the U.S.
Bankruptcy Court for the Southern District of New York. At the date of
Enron's bankruptcy, certain subsidiaries of AEP had open trading
contracts and trading accounts receivables and payables with Enron. In
addition, on June 1, 2001, AEP purchased Houston Pipe Line Company (HPL)
from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.

Commodity trading settlement disputes - In September 2003, Enron filed a
complaint in the Bankruptcy Court against AEPES challenging AEP's
offsetting of receivables and payables and related collateral across
various Enron entities and seeking payment of approximately $125 million
plus interest in connection with gas related trading transactions. AEP
has asserted its right to offset trading payables owed to various Enron
entities against trading receivables due to several AEP subsidiaries.
The parties are currently in non-binding court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court
against AEPSC seeking approximately $93 million plus interest in
connection with a transaction for the sale and purchase of physical
power among Enron, AEP and Allegheny Energy Supply, LLC during November
2001. Enron's claim seeks to unwind the effects of the transaction. AEP
believes it has several defenses to the claims in the action being
brought by Enron. The parties are currently in non-binding
court-sponsored mediation.

Enron bankruptcy summary - The amounts expensed in prior years in
connection with the Enron bankruptcy were based on an analysis of
contracts where AEP and Enron entities are counterparties, the
offsetting of receivables and payables, the application of deposits from
Enron entities and management's analysis of the HPL-related purchase
contingencies and indemnifications. As noted above, Enron has challenged
the offsetting of receivables and payables. Management is unable to
predict the outcome of these lawsuits or their impact on results of
operations, cash flows or financial condition.

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

Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider
(REP), filed a lawsuit in federal District Court in Corpus Christi,
Texas, in July 2003, against AEP and four of its 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 TCC and TNC, range from anticompetitive bidding to withholding
power. TCE alleges that these activities resulted in price spikes
requiring TCE to post additional collateral and ultimately forced it
into bankruptcy when it was unable to raise prices to its customers due
to fixed price contracts. The suit alleges over $500 million in damages
for all defendants and seeks recovery of damages, exemplary damages and
court costs. Two additional parties, Utility Choice, LLC and Cirro
Energy Corporation, have sought leave to intervene as plaintiffs
asserting similar claims. AEP and its subsidiaries filed a Motion to
Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. AEP and its subsidiaries filed a Motion to Dismiss the
amended complaint. In June 2004, the Court dismissed all claims against
AEP and its subsidiaries. TCE has appealed the trial court's decision to
the United States Court of Appeals for the Fifth Circuit.

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

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

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. In
January 2004, the CFTC issued a request for documents and other
information in connection with a CFTC investigation of activities
affecting the price of natural gas in the fall of 2003. AEP responded to
that request. The case is in the initial pleading stage with our
response to the complaint currently due on September 13, 2004. Although
management is unable to predict the outcome of this case, AEP recorded a
provision in 2003 and the action is not expected to have a material
effect on future results of operations, financial condition or cash
flows. Management cannot predict whether these governmental agencies
will take further action with respect to these matters.

SWEPCo Notice of Enforcement and Notice of Citizen Suit
-------------------------------------------------------

On July 13, 2004, two special interest groups issued a notice of intent
to commence a citizen suit under the Clean Air Act for alleged
violations of various permit conditions in permits issued to SWEPCo's
Welsh, Knox Lee, and Pirkey plants. This notice was prompted by allegations
made by a terminated AEP employee. The allegations at the Welsh Plant
concern compliance with emission limitations on particulate matter and
carbon monoxide, compliance with a referenced design heat input valve,
and compliance with certain reporting requirements. The allegations at
the Knox Lee Plant relate to the receipt of an off-specification fuel
oil, and the allegations at Pirkey Plant relate to testing and reporting
of volatile organic compound emissions. No action can be commenced until
60 days after the date of notice.

On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ)
issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant
containing a summary of findings resulting from a compliance
investigation at the plant. The summary includes allegations concerning
compliance with certain recordkeeping and reporting requirements,
compliance with a referenced design heat input valve in the Welsh
permit, compliance with a fuel sulfur content limit, and compliance with
emission limits for sulfur dioxide.

SWEPCo has previously reported to the TCEQ, deviations related to the
receipt of off-specification fuel at Knox Lee, and the referenced
recordkeeping and reporting requirements and heat input valve at Welsh.
We are preparing additional responses to the Notice of Enforcement and
the notice from the special interest groups. Management is unable to
predict the timing of any future action by TCEQ or the special interest
groups or the effect of such actions on results of operations, cash
flows or financial condition.

Carbon Dioxide Public Nuisance Claims
-------------------------------------

On July 21, 2004, attorneys general from eight states and the
corporation counsel for the City of New York filed an action in federal
district court for the Southern District of New York against AEP, AEPSC
and four other unaffiliated governmental and investor-owned electric
utility systems. That same day, a similar complaint was filed in the
same court against the same defendants by the Natural Resources Defense
Counsel on behalf of two special interest groups. The actions allege
that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts
associated with global warming, and seek injunctive relief in the form
of specific emission reduction commitments from the defendants.
Management believes the actions are without merit and intends to
vigorously defend against the claims.

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

As discussed in the 2003 Annual Report, there are emerging environmental
control requirements that management expects will result in substantial
capital investments and operational costs. The sources of these future
requirements include:

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

This discussion updates certain events occurring in 2004. You should
also read the "Significant Factors - Environmental Matters" section
within Registrants' Combined Management's Discussion and Analysis in the
2003 Annual Report for a complete description of all material
environmental matters affecting us, including, but not limited to, (1)
the current air quality regulatory framework, (2) estimated air quality
environmental investments, (3) Superfund and state remediation, (4)
global climate change, and (5) costs for spent nuclear fuel disposal and
decommissioning.

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

In 1997, the Federal EPA adopted new, more stringent national ambient
air quality standards for fine particulate matter and ground-level
ozone. The Federal EPA is in the process of developing final
designations for fine particulate matter non-attainment areas. The
Federal EPA finalized designations for ozone non-attainment areas on
April 15, 2004. On the same day, the Administrator of the Federal EPA
signed a final rule establishing the elements that must be included in
state implementation plans (SIPs) to achieve the new standards, and
setting deadlines ranging from 2008 to 2015 for achieving compliance
with the final standard, based on the severity of non-attainment. All or
parts of 474 counties are affected by this new rule, including many
urban areas in the Eastern United States.

The Federal EPA identified SO2 and NOx emissions as precursors to the
formation of fine particulate matter. NOx emissions are also identified
as a precursor to the formation of ground-level ozone. As a result,
requirements for future reductions in emissions of NOx and SO2 from the
AEP System's generating units are highly probable. In addition, the
Federal EPA proposed a set of options for future mercury controls at
coal-fired power plants.

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

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

 o  The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to
    reduce SO2 and NOx emissions across the eastern half of the
    United States (29 states and the District of Columbia) and
    make progress toward attainment of the new fine particulate
    matter and ground-level ozone national ambient air quality
    standards. These reductions could also satisfy these states'
    obligations to make reasonable progress towards the national
    visibility goal under the regional haze program.
 o  The Federal EPA proposed to regulate mercury emissions from coal-fired
    electric generating units.

The interstate air quality rule would require affected states to
include, in their SIPs, a program to reduce NOx and SO2 emissions from
coal-fired electric utility units. SO2 and NOx emissions would be
reduced in two phases, which would be implemented through a
cap-and-trade program. Regional SO2 emissions would be reduced to 3.9
million tons by 2010 and to 2.7 million tons by 2015. Regional NOx
emissions would be reduced to 1.6 million tons by 2010 and to 1.3
million tons by 2015. Rules to implement the SO2 and NOx trading
programs were proposed on June 10, 2004.

On April 15, 2004, the Federal EPA Administrator signed a proposed rule
detailing how states should analyze and include "Best Available
Retrofit" requirements for individual facilities in their SIPs to
address regional haze. The guidance applies to facilities built between
1962 and 1977 that emit more than 250 tons per year of certain regulated
pollutants in specific industrial categories, including utility boilers.
The Federal EPA included an alternative "Best Available Retrofit"
program based on emissions budgeting and trading programs. For utility
units that are affected by the CAIR, described above, the Federal EPA
proposed that participation in the trading program under the CAIR would
satisfy any applicable "Best Available Retrofit" requirements. However,
the guidance preserves the ability of a state to require site-specific
installation of pollution control equipment through the SIP for purposes
of abating regional haze.

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

The Federal EPA recommends, and AEP supports, a second mercury emission
reduction option. The second option would permit mercury emission
reductions to be achieved from existing sources through a national
cap-and-trade approach. The cap-and-trade approach would include a
two-phase mercury reduction program for coal-fired utilities. This
approach would coordinate the reduction requirements for mercury with
the SO2 and NOx reduction requirements imposed on the same sources under
the CAIR. Coordination is significantly more cost-effective because
technologies like scrubbers and SCRs, which can be used to comply with
the more stringent SO2 and NOx requirements, have also proven effective
in reducing mercury emissions on certain coal-fired units that burn
bituminous coal. The second option contemplates reducing mercury
emissions from 48 tons to 34 tons by 2010 and to 15 tons by 2018. A
supplemental proposal including unit-specific allocations and a
framework for the emissions budgeting and trading program preferred by
the Federal EPA was published in the Federal Register on March 16, 2004.
We filed comments on both the initial proposal and the supplemental
notice in June 2004.

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

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

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

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

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

On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in
order to "perfect" its complaint in the pending litigation. The NOV
expands the number of alleged "modifications" undertaken at the Amos,
Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek
plants during scheduled outages on these units from 1979 through the
present. Approximately one-third of the allegations in the NOV are
already contained in allegations made by the states or the special
interest groups in the pending litigation. The Federal EPA is expected
to file a motion to amend its complaint, and, to the extent that motion
seeks to expand the scope of the pending litigation, the AEP
subsidiaries will oppose that motion.

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

In other pending CAA litigation against unaffiliated utility companies
referenced in the annual report, the petition for certiorari filed with
the Supreme Court in the TVA litigation was denied by the Court on May
3, 2004. In addition, the United States has filed a notice of appeal
with the Fourth Circuit Court of Appeals from the adverse decision in
the Duke case, and a briefing order has been issued by the Court that
will require briefing to be completed by late September 2004.

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

On July 9, 2004, the Federal EPA published in the Federal Registrar a
rule pursuant to the Clean Water Act that will require all large
existing, once-through cooled power plants to meet certain performance
standards to reduce the mortality of juvenile and adult fish or other
larger organisms pinned against a plant's cooling water intake screens.
All plants must reduce fish mortality by 80% to 95%. A subset of these
plants that are located on sensitive water bodies will be required to
meet additional performance standards for reducing the number of smaller
organisms passing through the water screens and the cooling system.
These plants must reduce the rate of smaller organisms passing through
the plant by 60% to 90%. Sensitive water bodies are defined as oceans,
estuaries, the Great Lakes, and small rivers with large plants. These
rules will result in additional capital and operation and maintenance
expenses to ensure compliance. The estimated capital cost of compliance
for the AEP System's facilities, based on the Federal EPA's estimates in
the rule, is $193 million. Any capital costs associated with compliance
activities to meet the new performance standards would likely be
incurred during the years 2008 through 2010. Management has not
independently confirmed the accuracy of the Federal EPA's estimate. The
rule has provisions to limit compliance costs. Management may propose
less costly site-specific performance criteria if compliance cost
estimates are significantly greater than the Federal EPA's estimates or
greater than the environmental benefits. The rule also allows for
mitigation (also called restoration measures) if it is less costly and
has equivalent or superior environmental benefits than meeting the
criteria in whole or in part. Several states, electric utilities
(including APCo) and environmental groups appealed certain aspects of
the rule. Management cannot predict the outcome of the appeals. The
following table shows the investment amount per subsidiary.

                                         Estimated
                                        Compliance
                                        Investments
                                        -----------
                                       (in millions)

       APCo                                  $21
       CSPCo                                  19
       I&M                                   118
       OPCo                                   31

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

As discussed in the 2003 Annual Report, there are several "Other
Matters" affecting AEP subsidiaries, including FERC's proposed standard
market design and FERC's market power mitigation efforts. There were no
significant changes to the status of FERC's proposed standard market
design. The current status of FERC's market power mitigation efforts is
described below.

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

A FERC order issued in November 2001 on AEP's triennial market-based
wholesale power rate authorization update required certain mitigation
actions that AEP would need to take for sales/purchases within its
control area and required AEP to post information on its website
regarding its power system's status. As a result of a request for
rehearing filed by AEP and other market participants, FERC issued an
order delaying the effective date of the mitigation plan until after a
planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a
technical conference in January 2004. In April 2004, the FERC issued two
orders concerning utilities' ability to sell wholesale electricity at
market based rates. In the first order, the FERC adopted two new interim
screens for assessing potential generation market power of applicants
for wholesale market based rates, and described additional analyses and
mitigation measures that could be presented if an applicant does not
pass one of these interim screens. AEP and two unaffiliated utilities
were required to submit generation market power analyses within sixty
days of the FERC's order. In July 2004, the FERC issued an order on
rehearing affirming its conclusions in the April order and directing AEP
and two unaffiliated utilities to file generation market power analyses
within 30 days. In the second order, the FERC initiated a rulemaking to
consider whether the FERC's current methodology for determining whether
a public utility should be allowed to sell wholesale electricity at
market-based rates should be modified in any way. We plan to present
evidence to demonstrate that we do not possess market power in geographic
areas where we sell wholesale power.


<PAGE>

                             CONTROLS AND PROCEDURES
                             -----------------------

During the second quarter of 2004, management, including the principal executive
officer and principal financial officer of AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC (collectively, the Registrants), evaluated the
Registrants' disclosure controls and procedures relating to the recording,
processing, summarization and reporting of information in the Registrants'
periodic reports filed with the SEC. These disclosure controls and procedures
have been designed to ensure that (a) material information relating to the
Registrants is made known to the Registrants' management, including these
officers, by other employees of the Registrants, and (b) this information is
recorded, processed, summarized, evaluated and reported, as applicable, within
the time periods specified in the SEC's rules and forms. The Registrant's
controls and procedures can only provide reasonable, not absolute, assurance
that the above objectives have been met.

As of June 30, 2004, these officers concluded that the disclosure controls and
procedures in place provide reasonable assurance that the disclosure controls
and procedures accomplished their objectives. The Registrants 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 events
warrant.

There have been no changes in the Registrants' internal controls over financial
reporting (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the
Exchange Act) during the second quarter of 2004 that have materially affected,
or are reasonably likely to materially affect, the Registrants' internal control
over financial reporting.

<PAGE>

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings
         -----------------
          For a discussion of material legal proceedings, see Note 5,
          Commitments and Contingencies, incorporated herein by reference.

Item 2.  Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
          Securities
         ---------------------------------------------------------------------
          The following table provides information about purchases by AEP (or
          its publicly-traded subsidiaries) during the quarter ended June 30,
          2004 of equity securities that are registered by AEP (or its
          publicly-traded subsidiaries) pursuant to Section 12 of the Exchange
          Act:

<TABLE>
<CAPTION>

                                                          ISSUER PURCHASES OF EQUITY SECURITIES


                                                                                                              Maximum Number
                                                                                                              (or Approximate
                                                                                         Total Number        Dollar Value) of
                                                                                   of Shares Purchased as   Shares that May Yet
                                                                                     Part of Publicly        Be Purchased
                                          Total Number             Average Price      Announced Plans        Under the Plans
                   Period            of Shares Purchased (1)      Paid per Share        or Programs             or Programs
                   ------            -----------------------      --------------   ----------------------   -------------------
         <C>                                   <C>                      <C>                   <C>                   <C>
         04/01/04 - 04/30/04                   -                            $-                -                     $-
         05/01/04 - 05/31/04                   5                         70.00                -                      -
         06/01/04 - 06/30/04                   3                         69.00                -                      -
                                               --                       -------               --                    ---
         Total                                 8                        $69.63                -                     $-
                                               ==                       =======               ==                    ===

         (1) TCC and OPCo repurchased an aggregate of 5 shares of its 4% cumulative preferred stock and 3 shares of its 4.5%
         cumulative preferred stock, respectively, in privately-negotiated transactions outside of an announced program.

</TABLE>

Item 4.  Submission of Matters to a Vote of Security Holders
         ---------------------------------------------------

         AEP

         The annual meeting of shareholders was held in Columbus, Ohio, on April
         27, 2004. The holders of shares entitled to vote at the meeting or
         their proxies cast votes at the meeting with respect to the following
         six matters, as indicated below:

          1.    Election of eleven directors to hold office until the next
                annual meeting and until their successors are duly elected. Each
                nominee for director received the votes of shareholders as
                follows:

                                             No. of Shares      No. of Shares
                                               Voted For          Abstaining
                                             -------------      -------------

                  E. R. Brooks                304,880,019         8,450,055
                  Donald M. Carlton           301,928,439        11,401,635
                  John P. DesBarres           304,936,922         8,393,152
                  Robert W. Fri               305,300,688         8,029,386
                  William R. Howell           305,172,590         8,157,484
                  Lester A. Hudson, Jr.       300,799,680        12,530,394
                  Leonard J. Kujawa           301,737,241        11,592,833
                  Michael G. Morris           300,949,642        12,380,432
                  Richard L. Sandor           303,225,412        10,104,662
                  Donald G. Smith             303,120,154        10,209,920
                  Kathryn D. Sullivan         302,132,773        11,197,301

          2.    Ratification of the appointment of the firm of Deloitte &
                Touche LLP as the independent auditors for 2004.  The proposal
                was approved by a vote of the shareholders as follows:

                     Votes FOR                           296,126,400
                     Votes AGAINST                        15,883,072
                     Votes ABSTAINED                       1,320,602
                      Broker NON-VOTES*                            0

          3.    Shareholder proposal submitted by the International Brotherhood
                of Electrical Workers' Pension Benefit Fund urging the Board of
                Directors to seek shareholder approval of certain future
                severance agreements with senior executives. The proposal was
                approved by a vote of the shareholders as follows:

                     Votes FOR                           149,622,711
                     Votes AGAINST                       108,314,061
                     Votes ABSTAINED                       5,307,905
                      Broker NON-VOTES*                   50,085,397

          4.    Shareholder proposal submitted by the AFL-CIO Reserve Fund
                urging the Board of Directors to seek shareholder approval of
                certain future extraordinary pension benefits for senior
                executives. The proposal was disapproved by a vote of the
                shareholders as follows:

                     Votes FOR                            73,773,833
                     Votes AGAINST                       184,152,624
                     Votes ABSTAINED                       5,318,220
                      Broker NON-VOTES*                   50,085,397

          5.    Shareholder proposal submitted by the United Association S&P 500
                Fund requesting the Board of Directors and its Audit Committee
                adopt a policy that would limit the work performed by the public
                accounting firm retained by the Company to "audit" and
                "audit-related" services. The proposal was disapproved by a vote
                of the shareholders as follows:

                     Votes FOR                            36,206,757
                     Votes AGAINST                       221,661,710
                     Votes ABSTAINED                       5,376,210
                      Broker NON-VOTES*                   50,085,397

          6.    Shareholder proposal submitted by Mr. Ronald Marsico seeking to
                limit the maximum amount of service by any Director, except for
                the Chief Executive Officer and the President, to eight terms of
                office. The proposal was disapproved by a vote of the
                shareholders as follows:

                     Votes FOR                            21,178,705
                     Votes AGAINST                       236,643,469
                     Votes ABSTAINED                       5,422,499
                      Broker NON-VOTES*                   50,085,401

                *A non-vote occurs when a nominee holding shares for a
                beneficial owner votes on one proposal, but does not vote on
                another proposal because the nominee does not have discretionary
                voting power and has not received instructions from the
                beneficial owner.

           APCo

           The annual meeting of stockholders was held on April 27, 2004 at 1
           Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes
           were cast FOR each of the following nine persons for election as
           directors and there were no votes withheld and such persons were
           elected directors to hold office for one year or until their
           successors are elected and qualify:

                           Jeffrey D. Cross             Robert P. Powers
                           Henry W. Fayne               Thomas V. Shockley, III
                           Thomas M. Hagan              Stephen P. Smith
                           Michael G. Morris            Susan Tomasky
                           Armando A. Pena
           TCC

           Pursuant to action by written consent in lieu of an annual meeting
           of the sole shareholder dated April 8, 2004, the following nine
           persons were elected directors to hold office for one year or until
           their successors are elected and qualify:

                           Jeffrey D. Cross             Robert P. Powers
                           Henry W. Fayne               Thomas V. Shockley, III
                           Thomas M. Hagan              Stephen P. Smith
                           Michael G. Morris            Susan Tomasky
                           Armando A. Pena

           I&M

           Pursuant to action by written consent in lieu of an annual meeting
           of the sole shareholder dated April 27, 2004, the following thirteen
           persons were elected directors to hold office for one year or until
           their successors are elected and qualify:

                           Karl G. Boyd                 Susanne M. Moorman
                           John E. Ehler                Michael G. Morris
                           Henry W. Fayne               Robert P. Powers
                           Thomas M. Hagan              John R. Sampson
                           Patrick C. Hale              Thomas V. Shockley, III
                           David L. Lahrman             Susan Tomasky
                           Marc E. Lewis


           OPCo

           The annual meeting of shareholders was held on May 4, 2004 at 1
           Riverside Plaza, Columbus, Ohio. At the meeting there were 27,952,473
           votes cast FOR each of the following nine persons for election as
           directors and there were no votes withheld and such persons were
           elected directors to hold office for one year or until their
           successors are elected and qualify:

                           Jeffrey D. Cross             Robert P. Powers
                           Henry W. Fayne               Thomas V. Shockley, III
                           Thomas M. Hagan              Stephen P. Smith
                           Michael G. Morris            Susan Tomasky
                           Armando A. Pena

           SWEPCo

           Pursuant to action by written consent in lieu of an annual meeting
           of the sole shareholder dated April 14, 2004, the following nine
           persons were elected directors to hold office for one year or until
           their successors are elected and qualify:

                           Jeffrey D. Cross             Robert P. Powers
                           Henry W. Fayne               Thomas V. Shockley, III
                           Thomas M. Hagan              Stephen P. Smith
                           Michael G. Morris            Susan Tomasky
                           Armando A. Pena


Item 5.  Other Information
         -----------------
                NONE

Item 6.  Exhibits and Reports on Form 8-K
         --------------------------------
    (a) Exhibits:
        --------

        AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

               Exhibit 12 - Computation of Consolidated Ratio of Earnings to
                            Fixed Charges.

        AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

               Exhibit 31.1 - Certification of Chief Executive Officer Pursuant
                              to Section 302 of the Sarbanes-Oxley Act of 2002.

               Exhibit 31.2 - Certification of Chief Financial Officer Pursuant
                              to Section 302 of the Sarbanes-Oxley Act of 2002.

               Exhibit 32.1 - Certification of Chief Executive Officer Pursuant
                              to Section 1350 of Chapter 63 of Title 18 of the
                              United States Code.

               Exhibit 32.2 - Certification of Chief Financial Officer Pursuant
                              to Section 1350 of Chapter 63 of Title 18 of the
                              United States Code.


(b)     Reports on Form 8-K:
        -------------------

        The following reports on Form 8-K were filed during the quarter ended
        June 30, 2004.

<TABLE>
<CAPTION>

 Company Reporting      Date of Report     Item Reported
 -----------------      --------------     -------------
       <C>              <C>                <C>        <C>
       AEP              April 27, 2004     Item 7.    Financial Statements and Exhibits
                                           Item 9.    Regulation FD Disclosure

       AEP              April 29, 2004     Item 7.    Financial Statements and Exhibits
                                           Item 12.   Results of Operations and Financial Condition

       PSO              June 7, 2004       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: August 6, 2004