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, 2002
                                       OR
              [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                     For The Transition Period from     to
<TABLE>
<CAPTION>
Commission      Registrant, State of Incorporation                            I.R. S. Employer
File Number     Address, and Telephone Number                                 Identification No.
-----------     -----------------------------                                 ------------------
<S>                                                                          <C>
1-3525          AMERICAN ELECTRIC POWER COMPANY, INC.                         13-4922640
                (A New York Corporation)
0-18135         AEP GENERATING COMPANY (An Ohio Corporation)                  31-1033833
1-3457          APPALACHIAN POWER COMPANY (A Virginia Corporation)            54-0124790
0-346           CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation)         74-0550600
1-2680          COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation)         31-4154203
1-3570          INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)       35-0410455
1-6858          KENTUCKY POWER COMPANY (A Kentucky Corporation)               61-0247775
1-6543          OHIO POWER COMPANY (An Ohio Corporation)                      31-4271000
0-343           PUBLIC SERVICE COMPANY OF OKLAHOMA                            73-0410895
                (An Oklahoma Corporation)
1-3146          SOUTHWESTERN ELECTRIC POWER COMPANY                           72-0323455
                (A Delaware Corporation)
0-340           WEST TEXAS UTILITIES  COMPANY (A Texas  Corporation)          75-0646790
                1  Riverside Plaza, Columbus, Ohio  43215-2373
                Telephone (614) 223-1000
</TABLE>

AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company,
Public  Service  Company of Oklahoma and West Texas  Utilities  Company 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.


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
                                          ------         ------


The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at July 31, 2002 was 338,835,220.
<PAGE>

         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                                    FORM 10-Q

                       For The Quarter Ended June 30, 2002
                                    CONTENTS
<TABLE>
<CAPTION>
                                                                                                                    Page
        Glossary of Terms                                                                                           i - ii
        Forward-Looking Information                                                                                 iii
<S>                                                                                                                 <C>
   Part I.  FINANCIAL INFORMATION
     Items          1 and 2 Financial Statements and Management's Discussion and
                    Analysis of Results of Operations:

                         American Electric Power Company, Inc. and Subsidiary Companies:
                              Management's Discussion and Analysis of Results of Operations                         A-1 - A-5
                              Consolidated Financial Statements                                                     A-6 - A-10

                         AEP Generating Company:
                              Management's Narrative Analysis of Results of Operations                              B-1
                              Financial Statements                                                                  B-2 - B-5

                         Appalachian Power Company, Inc. and Subsidiaries:
                              Management's Discussion and Analysis of Results of Operations                         C-1 - C-4
                              Consolidated Financial Statements                                                     C-5 - C-9

                         Central Power and Light Company and Subsidiaries:
                              Management's Discussion and Analysis of Results of Operations                         D-1 - D-4
                              Consolidated Financial Statements                                                     D-5 - D-8

                         Columbus Southern Power Company and Subsidiaries:
                              Management's Narrative Analysis of Results of Operations                              E-1 - E-5
                              Consolidated Financial Statements                                                     E-6 - E-9

                         Indiana Michigan Power Company and Subsidiaries:
                              Management's Discussion and Analysis of Results of Operations                         F-1 - F-5
                              Consolidated Financial Statements                                                     F-6 - F-10

                         Kentucky Power Company
                              Management's Narrative Analysis of Results of Operations                              G-1 - G-4
                              Financial Statements                                                                  G-5 - G-9

                         Ohio Power Company and Subsidiaries:
                              Management's Discussion and Analysis of Results of Operations                         H-1 - H-4
                              Consolidated Financial Statements                                                     H-5 - H-9

                         Public Service Company of Oklahoma and Subsidiaries:
                              Management's Narrative Analysis of Results of Operations                              I-1 - I-4
                              Consolidated Financial Statements                                                     I-5 - I-8

                         Southwestern Electric Power Company and Subsidiaries:
                              Management's Discussion and Analysis of Results of Operations                         J-1 - J-4
                              Consolidated Financial Statements                                                     J-5 - J-8

                         West Texas Utilities Company:
                              Management's Narrative Analysis of Results of Operations                              K-1 - K-4
                              Financial Statements                                                                  K-5 - K-8

                              Footnotes to Financial Statements                                                     L-1 - L-16
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S>                                                                                                                 <C>
           Item 2.        Registrants' Combined Management Discussion and Analysis of
                                 Financial Condition, Contingencies  and Other Matters                              M-1 - M-11
           Item 3.        Quantitative and Qualitative Disclosures About Market Risk                                N-1 - N-9

       Part II.           OTHER INFORMATION
           Item 4.             Submission of Matters to a Vote of Security Holders                                  O-1
           Item 5.             Other Information                                                                    O-3
           Item 6.             Exhibits and Reports on Form 8-K                                                     O-4
                                     (a)  Exhibits
                                           Exhibit 3 (d)
                                           Exhibit 3 (e)
                                           Exhibit 12
                                           Exhibit 99.1
                                           Exhibit 99.2
                                     (b)  Reports on Form 8-K

SIGNATURE                                                                                                           P-1
</TABLE>
     This  combined  Form 10-Q is separately  filed by American  Electric  Power
Company, Inc., AEP Generating Company,  Appalachian Power Company, Central Power
and Light  Company,  Columbus  Southern Power  Company,  Indiana  Michigan Power
Company,  Kentucky Power Company, Ohio Power Company,  Public Service Company of
Oklahoma,  Southwestern Electric Power Company and West Texas Utilities 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>
                                GLOSSARY OF TERMS
         When the following terms and  abbreviations  appear in the text of this
report, they have the meanings indicated below.
<TABLE>
<CAPTION>
               Term                                Meaning
<S>                                 <C>
2004 True-up Proceeding............ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the
                                            amount of stranded costs and the recovery of such costs.
AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP.
aEP................................ American Electric Power Company, Inc.
aEP Consolidated................... AEP and its majority owned subsidiaries consolidated.
aEP Credit, Inc.................... AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
                                            revenues for affiliated and unaffiliated domestic electric utility companies.
AEP East electric operating
companies.......................... APCo, CSPCo, I&M, KPCo and OPCo.
AEPR............................... AEP Resources, Inc.
aEP System or the System........... The American Electric Power System, an integrated electric utility system, owned and
                                            operated by AEP's electric utility subsidiaries.
AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and
                                            professional services to AEP and its subsidiaries.
aEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo.  The Pool shares the
                                            generation, cost of generation and resultant wholesale system sales of the member
                                            companies.
AEP West electric operating
companies.......................... CPL, PSO, SWEPCo and WTU.
Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
                                            utilities.
Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and
                                            OPCo.
APCo............................... Appalachian Power Company, an AEP electric utility subsidiary.
Buckeye............................ Buckeye Power, Inc., an unaffiliated corporation.
COLI............................... Corporate owned life insurance program.
Cook Plant......................... The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CPL................................ Central Power and Light Company, an AEP electric utility subsidiary.
CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW...............................  Central and South West Corporation, a subsidiary of AEP.
CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
                                            outside the United States.
D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit.
DOE................................ United States Department of Energy.
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.
IRS................................ Internal Revenue Service.
IURC............................... Indiana Utility Regulatory Commission.
ISO................................ Independent system operator.
KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary.
KPSC............................... Kentucky Public Service Commission.
KWH................................ Kilowatthour.
LIG................................ Louisiana Intrastate Gas.
Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
                                            customer choice of electricity supplier.
<PAGE>
MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool......................... AEP System's Money Pool.
MPSC............................... Michigan Public Service Commission.
MTN................................ Medium Term Notes.
MW................................. Megawatt.
MWH................................ Megawatthour.
NEIL............................... Nuclear Electric Insurance Limited.
NOx................................ Nitrogen oxide.
NOx Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states
                                            including seven of the states in which AEP companies operates.
NRC................................ Nuclear Regulatory Commission.
Ohio Act........................... The Ohio Electric Restructuring Act of 1999.
Ohio EPA........................... Ohio Environmental Protection Agency.
OPCo..............................  Ohio Power Company, an AEP electric utility subsidiary.
PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO................................ Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO............................... The Public Utilities Commission of Ohio.
PUCT............................... The Public Utility Commission of Texas.
PUHCA.............................. Public Utility Holding Company Act of 1935, as amended.
PURPA.............................. The Public Utility Regulatory Policies Act of 1978.
RCRA............................... Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............ AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
                                            SWEPCo and WTU.
Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
                                            Indiana owned by AEGCo and I&M.
RTO................................ Regional Transmission Organization.
SEC................................ Securities and Exchange Commission.
SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards
                                            Board.
SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain
                                                                                        -------------------------------------
                                            Types of Regulation.
                                            -------------------
SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of
                                                                                         ------------------------------------
                                            Application of Statement 71.
                                            ---------------------------
SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of
                                                                                         --------------------------------
                                            Long-Lived Assets and for Long-Lived Assets to be Disposed of.
                                            --------------------------------------------------------------
SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
                                                                                         -------------------------------------
                                            and Hedging Activities.
                                            ----------------------
SFAS 142........................... Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.
                                                                                         -------------------------------------
SFAS 144........................... Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or
                                                                                         --------------------------------
                                            Disposal of Long-lived Assets.
                                            -----------------------------
SNF................................ Spent Nuclear Fuel.
SPP................................ Southwest Power Pool.
STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light
                                            Company, an AEP electric utility subsidiary .
SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary.
Texas Restructuring Legislation.... Legislation  enacted in 1999 to  restructure the electric utility industry in Texas.
TVA ............................... Tennessee Valley Authority.
U.K................................ The United Kingdom.
VaR................................ Value at Risk, a method to quantify risk exposure.
Virginia SCC....................... Virginia State Corporation Commission.
WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary.
Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
                   Southern Power Company, an AEP subsidiary.
</TABLE>
<PAGE>
     FORWARD-LOOKING INFORMATION

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

o        Electric load and customer growth.
o        Abnormal weather conditions.
o        Available sources and costs of fuels.
o        Availability of generating capacity.
o        The  speed  and  degree  to  which  competition  is  introduced  to our
         power generation  business.
o        The structure and timing of a competitive market and its impact on
         energy prices or fixed rates.
o        The ability to recover  stranded costs in  connection  with
         possible/proposed   deregulation  of  generation.
o        New legislation and government regulations.
o        The ability of AEP to successfully control its costs.
o        The success of new business ventures.
o        International developments affecting AEP's foreign investments.
o        The economic climate and growth in AEP's service territory.
o        Inflationary trends.
o        Electricity and gas market prices.
o        Interest rates
o        Liquidity in the wholesale markets
o        Other risks and unforeseen events.

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

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

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

o        Wholesale
         o        Generation of electricity for sale to retail and wholesale
                  customers
         o        Gas pipeline and storage services
         o        Marketing and trading of electricity, gas and coal
         o        Coal mining, bulk commodity barging operations and other
                  energy supply related business.
o        Energy Delivery
         o        Domestic electricity transmission,
         o        Domestic electricity distribution
o        Other Investments
         o        Foreign electric distribution and supply investments,
         o        Telecommunication services.

Net Income

        Net income for the second  quarter was $62 million or $0.19 per share, a
decrease  of $170  million  or $0.53 per share.  AEP had a loss of $107  million
($0.33 per share)  year-to-date  compared with net income of $498 million ($1.54
per share) in 2001. A decline in system  sales and  margins, natural gas trading
losses and charges associated  with  the impairment  and  divesture  of  foreign
retail electricity and gas supply and distribution operations account for the
decrease.

Critical Accounting Policies - Revenue Recognition
Regulatory  Accounting  - As the  owner of  cost-based  rate-regulated  electric
public utility  companies,  AEP Co., Inc.'s  consolidated  financial  statements
reflect the actions of regulators that can result in the recognition of revenues
and  expenses in  different  time  periods  than  enterprises  that are not rate
regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and
regulatory  liabilities  (future revenue  reductions or refunds) are recorded to
reflect the  economic  effects of  regulation  by matching  expenses  with their
recovery through regulated revenues in the same accounting period.
        When regulatory assets are probable of recovery through regulated rates,
we record  them as assets  on the  balance  sheet.  We test for  probability  of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation.  If we determine that recovery of a regulatory asset
is no longer  probable,  we write off that regulatory  asset as a charge against
net income.  A write off of regulatory  assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general expenses are recorded when incurred.
<PAGE>
Domestic  Gas  Pipeline and Storage  Activities  - We  recognize  revenues  from
domestic gas pipeline and storage  services when gas is delivered to contractual
meter points or when services are provided.  Transportation and storage revenues
also include the accrual of earned, but unbilled and/or not yet metered gas.

Energy Marketing and Trading  Activities - We engage in non-regulated  wholesale
electricity  and  natural  gas  marketing  and  trading  transactions   (trading
activities).  Trading  activities  involve the purchase and sale of energy under
forward  contracts  at fixed and  variable  prices and the buying and selling of
financial  energy  contracts  which  include  exchange  futures  and options and
over-the-counter  options and swaps.  Although  trading  contracts are generally
short-term,  there are also long-term trading  contracts.  We recognize revenues
from  trading  activities  generally  based on changes in the fair value of open
energy trading contracts.
         Recording the net change in the fair value of open trading contracts as
revenues  prior to settlement is commonly  referred to as  mark-to-market  (MTM)
accounting.  Under MTM  accounting  the  change in the  unrealized  gain or loss
throughout a contract's term is recognized in each accounting  period.  When the
contract actually settles,  that is, the energy is actually  delivered in a sale
or received in a purchase or the parties  agree to forego  delivery  and receipt
and net settle in cash, the unrealized  gain or loss is reversed out of revenues
and the actual  realized  cash gain or loss is recognized in revenues for a sale
or in purchased  energy  expense for a purchase.  Therefore,  over the term of a
trading  contract an unrealized  gain or loss is  recognized  as the  contract's
market  value  changes.  When the  contract  settles  the total  gain or loss is
realized in cash but only the difference between the accumulated  unrealized net
gains or losses  recorded in prior months and the cash  proceeds is  recognized.
Unrealized  mark-to-market gains and losses are included in the Balance Sheet as
energy trading and derivative contract assets or liabilities.
         The  majority  of our trading  activities  represent  physical  forward
electricity  and gas  contracts  that are  typically  settled by  entering  into
offsetting contracts.  An example of our trading activities is when, in January,
we enter into a forward sales contract to deliver electricity or gas in July. At
the end of each month until the  contract  settles in July,  we would record any
difference between the contract price and the market price as an unrealized gain
or loss in revenues.  In July when the contract settles, we would realize a gain
or loss in cash and  reverse to  revenues  the  previously  recorded  cumulative
unrealized  gain or loss.  Prior to settlement,  the change in the fair value of
physical  forward sale and  purchase  contracts is included in revenues on a net
basis.  Upon  settlement of a forward trading  contract,  the amount realized is
included in revenues for a sales  contract and the realized  cost is included in
purchased  energy  expense  for a  purchase  contract  with the prior  change in
unrealized  fair  value  reversed in  revenues.  A  recently  issued  accounting
pronouncement will require us to report our trading transactions on a net  basis
beginning in the third quarter of 2002.  Our adoption of this new standard  will
lead to a material decrease in both revenues and  purchased energy expense.  See
"New Accounting Standard" section in Registrants' Combined Management Discussion
and Analysis of Financial Condition, Contingencies and Other Matters.
         Continuing  with the above  example,  assume  that  later in January or
sometime in February  through July we enter into an offsetting  forward contract
to buy  electricity  or gas in July. If we do nothing else with these  contracts
until  settlement in July and if the commodity  type,  volumes,  delivery point,
schedule  and other key terms match then the  difference  between the sale price
and the  purchase  price  represents  a fixed  value  to be  realized  when  the
contracts settle in July. If the purchase contract is perfectly matched with the
sales contract, we have effectively fixed the profit or loss; specifically it is

<PAGE>

the  difference  between the contracted  settlement  price of the two contracts.
Mark-to-market  accounting for these contracts from this point forward will have
no further impact on operating results but has an offsetting and equal effect on
trading  contract  assets and  liabilities.  Of course we could have also done a
similar  transaction but enter into a purchase contract prior to entering into a
sales  contract.  If the sale and purchase  contracts do not match exactly as to
commodity  type,  volumes,  delivery point,  schedule and other key terms,  then
there could be  continuing  mark-to-market  effects on revenues  from  recording
additional changes in fair values using mark-to-market accounting.
         Trading of electricity and gas options,  futures and swaps,  represents
financial  transactions  with  unrealized  gains and losses from changes in fair
values reported net in revenues until the contracts settle. When these contracts
settle, we record the net proceeds in revenues and reverse to revenues the prior
cumulative unrealized net gain or loss.
         The fair  value  of open  short-term  trading  contracts  are  based on
exchange  prices and broker quotes.  We  mark-to-market  open long-term  trading
contracts  based  mainly on  Company-developed  valuation  models.  These models
estimate  future  energy  prices based on existing  market and broker quotes and
supply and demand market data and  assumptions.  The fair values  determined are
reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is
the risk that the  counterparty  to the contract will fail to perform or fail to
pay amounts due AEP.  Liquidity risk represents the risk that  imperfections  in
the  market  will  cause  the  price to be less than or more than what the price
should be based purely on supply and demand. There are inherent risks related to
the underlying  assumptions in models used to fair value open long-term  trading
contracts.  We have independent  controls to evaluate the  reasonableness of our
valuation models. However,  energy markets,  especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ  from  actual  prices  throughout  a  contract's  term and when
contracts  settle.  Therefore,  there could be significant  adverse or favorable
effects on future  results  of  operations  and cash  flows if market  prices at
settlement do not correlate  with the  Company-developed  price models.  This is
particularly true for long-term contracts.
         We also  mark-to-market  derivatives that are not trading  contracts in
accordance  with  generally  accepted  accounting  principles.  Derivatives  are
contracts  whose  value is  derived  from  the  market  value  of an  underlying
commodity.
         We defer as regulatory  assets or liabilities  the effect on net income
of marking to market open forward electricity trading contracts in our regulated
jurisdictions  since  these  transactions  are  included in cost of service on a
settlement basis for ratemaking purposes.  Changes in mark-to-market  valuations
impact net income in our non-regulated gas and electricity business.
         Volatility in energy commodities markets affects the fair values of all
of our open  trading and  derivative  contracts  exposing AEP to market risk and
causing our results of operations to be subject to volatility. See "Quantitative
and  Qualitative  Disclosures  About Market Risks"  section of this report for a
discussion  of the  policies and  procedures  AEP uses to manage its exposure to
market and other risks from trading activities.


<PAGE>


RESULTS OF OPERATIONS
        Net income for the second  quarter of 2002 decreased by $170 million and
by $605 million  year-to-date.  Reduced  margins  resulting from lower wholesale
energy prices,  losses from gas trading and marketing and losses associated with
the  impairment  and divesture of SEEBOARD in the UK and CitiPower in Australia,
two foreign  retail  electricity  and gas supply and  distribution  investments,
account for the  decreases.  In 2002 the wholesale  energy sector has been under
pressure from lower commodity prices in contrast to last year when we had strong
performance from the wholesale business due to favorable market conditions. Also
contributing to the year-to-date decrease was a transitional goodwill impairment
loss related to SEEBOARD and  CitiPower  from the adoption of SFAS 142 (see Note
2) that has  been  reported  as a  cumulative  effect  of an  accounting  change
retroactive to January 1, 2002.
        The rise in revenues from gas marketing and trading can be attributed to
an increase in gas marketing and trading  volume,  up 123%  year-to-date,  as we
expanded  our gas  trading  operations  around  Houston  Pipe Line (HPL) that we
acquired in June 2001.  Gas marketing and trading volume also rose in the second
quarter as the Company continued unwinding positions that led to a first-quarter
gas trading loss.  The decrease in electric  marketing and trading  revenues was
largely  driven by the  decline in system  sales due to lower  wholesale  energy
prices that decreased margins.



<PAGE>

<TABLE>
<CAPTION>
                                                                 Increase (Decrease)
                                             Second Quarter                              Year-to-Date
                                     (in millions)          %                    (in millions)        %
                                                            -                                         -

<S>                                       <C>            <C>                      <C>              <C>
       Electricity Marketing
        And Trading*                      $ (558)          (6)                    $(1,306)           (7)
       Gas Marketing and Trading           1,289           36                       1,274            18
       Energy Delivery*                       13            1                          22             1
       Other Investments                      20           18                           8             3
                                          ------                                  -------
            Total                         $  764            5                     $    (2)            -
                                          ======                                  =======
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.
<TABLE>
<CAPTION>
        The changes in the total expenses were:
                                                                                 Increase (Decrease)
                                                                Second Quarter                           Year-to-Date
                                                        (in millions)           %               (in millions)         %
                                                                                -                                     -
<S>                                                              <C>          <C>                 <C>                <C>
       Fuel and Purchased Energy:
         Electricity Marketing
          And Trading                                            $ (967)      (11)                $(1,899)           (11)
         Gas Marketing and Trading                                1,528        45                   1,663             24
         Other Investments                                           24        46                      61             59
       Maintenance and Other Operation                              423        47                     519             29
       Depreciation and Amortization                                 38        12                      68             11
       Taxes other Than Income Taxes                                  9         5                      27              8
                                                                 ------                            ------
                                                                 $1,055         8                  $  439              2
                                                                 ======                            ======
</TABLE>
        The  decrease  in  fuel  and  purchased  energy  expense  was  primarily
attributable  to a reduction in power  generation  and  purchases and lower fuel
costs  reflecting  lower market prices than in the second  quarter of 2001.  Net
generation  decreased  1.2%  from  last  year  due to  the  reduced  demand  for
electricity  and planned  maintenance  outages for various  plants.  The cost of
purchased  power  for  resale  was  also  lower  due  to  reduced  demand  and a
continuation  of the market  conditions  that developed in the fourth quarter of
2001.  The increase in gas marketing and trading  purchased  energy  expense was
primarily  due to an expansion of gas trading  activity  around our HPL pipeline
assets.

<PAGE>

        Maintenance and other operation expense increased largely as a result of
material  and labor  costs  incurred  in  connection  with the  construction  of
gas-fired plants for third parties; the expenses of recently acquired businesses
MEMCO, a barging line; Quaker Coal; and two power plants in the UK; and a charge
associated  with  the  impairment  and   divestiture  of  CitiPower,   a  retail
electricity and gas supply and distribution subsidiary in Australia.  These cost
increases   were   partially   offset  by  a  reduction  in  trading   incentive
compensation.  Project fees for the  construction of gas-fired  plants for third
parties are  recognized  in  revenues  on a  percentage  of  completion  method,
consequently,  the  charges  to  expense  for  material  and labor  costs do not
adversely  affect net income.  On July 19,  2002,  AEP,  through a wholly  owned
subsidiary  entered  into an  agreement  to sell  CitiPower,  and recorded a net
impairment  charge  totaling $125 million.  $163 million  (excluding  tax of $65
million) was recorded in operating  expenses in the second  quarter of 2002 (see
Note  3).  $27  million  of  net  impairment  loss  has  been  classified  as  a
transitional goodwill impairment loss from the adoption of SFAS 142 (see Note 2)
and has been recorded as a cumulative effect of an accounting change retroactive
to January 1, 2002.
        Other  income  decreased  due to the gain from the sale of  Frontera  in
2001.
        The decrease in income taxes is predominately due to a decrease in
pre-tax income.
        The decrease in interest was primarily due to the refinancing of debt at
favorable interest rates and a reduction in short-term interest rates.



<PAGE>
<TABLE>
<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED STATEMENTS OF INCOME
                     (in millions, except per-share amounts)
                                   (UNAUDITED)
                                                          Three Months Ended              Six Months Ended
                                                               June 30,                       June 30,
                                                           2002             2001           2002           2001
                                                           ----             ----           ----           ----

REVENUES:
<S>                                                      <C>              <C>            <C>            <C>
   Electricity Marketing and Trading                      $9,001           $9,559        $17,525        $18,831
   Gas Marketing and Trading                               4,886            3,597          8,477          7,203
   Domestic Electric Delivery                                896              883          1,694          1,672
   Other Investments                                         129              109            246            238
                                                         -------          -------        -------        -------
          TOTAL REVENUES                                  14,912           14,148         27,942         27,944
                                                         -------          -------        -------        -------
EXPENSES:
   Fuel and Purchased Energy:
     Electricity Marketing and Trading                     7,757            8,724         15,046         16,945
     Gas Marketing and Trading                             4,929            3,401          8,602          6,939
     Other Investments                                        76               52            165            104
                                                         -------          -------        -------        -------
           TOTAL FUEL AND PURCHASED ENERGY                12,762           12,177         23,813         23,988
                                                         -------          -------        -------        -------
   Maintenance and Other Operation                         1,332              909          2,325          1,806
   Depreciation and Amortization                             367              329            710            642
   Taxes Other Than Income Taxes                             178              169            364            337
                                                         -------          -------        -------        -------
          TOTAL EXPENSES                                  14,639           13,584         27,212         26,773
                                                         -------          -------        -------        -------
OPERATING INCOME                                             273              564            730          1,171
OTHER INCOME                                                  46              101             63            154
OTHER EXPENSE                                                  7               28             29             47
LESS: INTEREST                                               204              217            414            464
      PREFERRED STOCK DIVIDEND REQUIREMENTS
       OF SUBSIDIARIES                                         3                2              5              5
      MINORITY INTEREST IN FINANCE SUBSIDIARY                  9             -                18        .  -
                                                         -------          -------        -------        -------
INCOME BEFORE INCOME TAXES                                    96              418            327            809
INCOME TAXES                                                  38              163            120            321
                                                         -------          -------        -------        -------
INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS,
 EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A
 CHANGE IN ACCOUNTING PRINCIPLE                               58              255            207            488
  Discontinued Operations (net of tax)                         4               25             36             58
  Extraordinary Loss - (net of tax)                         -                 (48)           -              (48)
  Cumulative Effect of Goodwill Transition
   Impairment                                               -                -              (350)          -
                                                         -------          -------        -------        -------
NET INCOME (LOSS)                                        $    62          $   232        $  (107)       $   498
                                                         =======          =======        ========       =======
AVERAGE NUMBER OF SHARES OUTSTANDING                         326              322            324            322
                                                             ===              ===            ===            ===
EARNINGS (LOSS) PER SHARE (BASIC AND DULUTIVE):
   Income Before Discontinued Operations,
    Extraordinary Item and Cumulative Effect of a
    Change in Accounting Principle                        $ 0.18           $ 0.79         $ 0.64          $1.51
   Discontinued Operations                                  0.01             0.08           0.11           0.18
   Extraordinary Loss                                        -              (0.15)           -            (0.15)
   Cumulative Effect of a Change in Accounting
    Principle                                                -                -            (1.08)           -
                                                          ------           ------         ------          -----
   EARNINGS (LOSS) PER SHARE (BASIC AND DILUTIVE)         $ 0.19           $ 0.72         $(0.33)         $1.54
                                                          ======           ======         ======          =====

CASH DIVIDENDS PAID PER SHARE                              $0.60            $0.60          $1.20          $1.20
                                                           =====            =====          =====          =====
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                               June 30, 2002            December 31, 2001
                                                                            (in millions)
<S>                                                                  <C>                         <C>
ASSETS
------
CURRENT ASSETS:
    Cash and Cash Equivalents                                        $   585                     $   244
    Accounts Receivable (net)                                          2,638                       1,687
    Fuel, Materials and Supplies                                       1,146                       1,048
    Energy Trading and Derivative Contracts                            9,466                       8,572
    Other                                                              1,276                         688
                                                                     -------                     -------

       TOTAL CURRENT ASSETS                                           15,111                      12,239
                                                                     -------                     -------

PROPERTY, PLANT AND EQUIPMENT:
   Electric:
     Production                                                       18,090                      17,477
     Transmission                                                      5,971                       5,879
     Distribution                                                      9,827                       9,661
   Other (including gas, coal mining and
     nuclear fuel)                                                     4,086                       4,597
   Construction Work in Progress                                       1,274                       1,102
                                                                     -------                     -------
       Total Property, Plant and Equipment                            39,248                      38,716
   Accumulated Depreciation and Amortization                          15,807                      15,456
                                                                     -------                     -------

       NET PROPERTY, PLANT AND EQUIPMENT                              23,441                      23,260
                                                                     -------                     -------

REGULATORY ASSETS                                                      2,314                       3,162
                                                                     -------                     -------

SECURITIZED TRANSITION ASSET                                             751                        -
                                                                     -------                     -------

INVESTMENTS IN POWER, DISTRIBUTION AND
  COMMUNICATIONS PROJECTS                                                540                         633
                                                                     -------                     -------

ASSETS HELD FOR SALE                                                   2,750                       2,832
                                                                     -------                     -------

GOODWILL                                                                 482                         417
                                                                     -------                     -------

INTANGIBLE ASSETS                                                        366                         474
                                                                     -------                     -------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                      3,672                       2,370
                                                                     -------                     -------

OTHER ASSETS                                                           1,731                       1,894
                                                                     -------                     -------

          TOTAL                                                      $51,158                     $47,281
                                                                     =======                     =======
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)
                                                                 June 30, 2002            December 31, 2001
                                                                 -------------            -----------------
                                                                                   (in millions)
<S>                                                                     <C>                            <C>
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
  Accounts Payable                                                      $ 2,641                        $ 1,985
  Short-term Debt                                                         3,041                          4,011
  Long-term Debt Due Within One Year                                      1,506                          1,114
  Energy Trading And Derivative Contracts                                 9,538                          8,311
  Other                                                                   1,789                          1,926
                                                                        -------                        -------

       TOTAL CURRENT LIABILITIES                                         18,515                         17,347
                                                                       --------                        -------

LONG-TERM DEBT                                                           10,094                          9,052
                                                                        -------                        -------

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

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                         3,444                          2,183
                                                                        -------                        -------

DEFERRED INCOME TAXES                                                     4,326                          4,555
                                                                        -------                        -------

DEFERRED INVESTMENT TAX CREDITS                                             474                            491
                                                                        -------                        -------

DEFERRED CREDITS AND REGULATORY LIABILITIES                                 863                            871
                                                                        -------                        -------

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2                 190                            194
                                                                        -------                        -------

OTHER NONCURRENT LIABILITIES                                              1,321                          1,334
                                                                        -------                        -------

LIABILITIES HELD FOR SALE                                                 1,955                          1,798
                                                                        -------                        -------

COMMITMENTS AND CONTINGENCIES (Note 8)

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

MINORITY INTEREST IN FINANCE SUBSIDIARY                                     750                            750
                                                                        -------                        -------

CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES                                 145                            156
                                                                        -------                        -------

COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
                                2002           2001
                                ----           ----
      Shares Authorized. . .600,000,000     600,000,000
      Shares Issued. . . . .347,833,712     331,234,997
      (8,999,992 shares were held in treasury at
       June 30, 2002 and December 31, 2001)                               2,261                          2,153
  Paid-in Capital                                                         3,413                          2,906
  Accumulated Other Comprehensive Income (Loss)                             (92)                          (126)
  Retained Earnings                                                       2,802                          3,296
                                                                        -------                        -------

          TOTAL COMMON SHAREHOLDERS' EQUITY                               8,384                          8,229
                                                                        -------                        -------

              TOTAL                                                     $51,158                        $47,281
                                                                        =======                        =======
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                             Six Months Ended June 30,
                                                                         2002                  2001
                                                                         ----                  ----
                                                                              (in millions)
<S>                                                                    <C>                    <C>
OPERATING ACTIVITIES:
   Net Income (Loss)                                                    $ (107)               $   498
   Adjustments for Noncash Items:
      Depreciation and Amortization                                        710                    664
      Deferred Federal Income Taxes                                       (111)                    11
      Deferred Investment Tax Credits                                      (10)                   (17)
      Amortization of Deferred Property Taxes                               35                     82
      Amortization of Cook Plant Restart Costs                              20                     20
      Deferred Costs Under Fuel Clause Mechanisms                          (35)                    50
      Transitional Impairment of Goodwill                                  350                   -
      Provision for Loss on CitiPower                                       98                   -
      Discontinued Operations                                              (36)                   (58)
      Extraordinary Loss - Effects of Deregulation                        -                        48
      Mark to Market on Open Energy Trading Contracts                      (87)                  (260)
      Realized Mark to Market on Settled Energy Trading Contracts          294                     (5)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                           (941)                (1,205)
      Fuel, Materials and Supplies                                         250                   (108)
      Accrued Utility Revenues                                            (182)                   (84)
      Prepayments and Other                                                (73)                     1
      Accounts Payable                                                     354                 (1,643)
      Taxes Accrued                                                        (15)                    53
      Interest Accrued                                                      57                     48
   Option Premiums                                                          49                   (161)
   Change in Other Assets                                                 (841)                 2,694
   Change in Other Liabilities                                             317                    (63)
                                                                       -------                -------
          Net Cash Flows From Operating Activities                          96                    565
                                                                       -------                -------
INVESTING ACTIVITIES:
  Construction Expenditures                                               (783)                  (812)
  Purchase of Houston Pipe Line                                           -                      (727)
  Sale of Yorkshire                                                       -                       383
  Sale of Frontera                                                        -                       265
  Other                                                                    (21)                   (97)
                                                                       -------                -------
          Net Cash Flows Used For Investing Activities                    (804)                  (988)
                                                                       -------                -------
FINANCING ACTIVITIES:
  Issuance of Common Stock                                                 656                      9
  Issuance of Long-term Debt                                             1,786                  1,388
  Issuance of Equity Unit Senior Notes                                     334                   -
  Change in Short-term Debt (net)                                         (970)                  (275)
  Retirement of Long-term Debt                                            (357)                  (463)
  Dividends Paid on Common Stock                                          (387)                  (387)
                                                                       -------                -------
            Net Cash Flows From Financing Activities                     1,062                    272
                                                                       -------                -------
Effect of Exchange Rate Change on Cash                                     (13)                  -
                                                                       -------                -------
Net Increase (Decrease) in Cash and Cash Equivalents                       341                   (151)
Cash and Cash Equivalents at Beginning of Period                           244                    363
                                                                       -------                -------
Cash and Cash Equivalents at End of Period                             $   585                $   212
                                                                       =======                =======
</TABLE>
Supplemental Disclosure:
Cash paid for  interest  net of  capitalized  amounts was $335  million and $342
million and for income taxes was $307 million and $107 million in 2002 and 2001,
respectively.  Noncash acquisitions under capital leases were $2 million in 2002
and $21 million in 2001, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
                                   (UNAUDITED)
                                                                                    Accumulated
                                                                                    Other
                                          Common       Paid-in       Retained       Comprehensive
                                          Stock        Capital       Earnings       Income (Loss)         Total
                                          -----        -------       --------       -------------         -----
                                                                    (in millions)
<S>                                      <C>           <C>            <C>                 <C>             <C>
JANUARY 1, 2001                          $2,152        $2,915         $3,090              $(103)          $8,054
Issuance of Common Stock                      1             8                                                  9
Common Stock Dividends                                                  (387)                               (387)
Other                                                      (7)             9                                   2
                                                                                                          ------
                                                                                                           7,678
Comprehensive Income:
  Other Comprehensive Income,
   Net of Taxes
     Currency Translation Adjustment                                                        (53)             (53)
     Unrealized Gain on
      Hedged Derivative                                                                      31               31
     Minimum Pension Liability                                                               (6)              (6)
  Net Income                                                             498                                 498
                                                                                                          ------
     Total Comprehensive Income                                                                              470
                                         ------        ------         ------              -----           ------

JUNE 30, 2001                            $2,153        $2,916         $3,210              $(131)          $8,148
                                         ======        ======         ======              =====           ======



JANUARY 1, 2002                          $2,153        $2,906         $3,296              $(126)          $8,229
Issuance of Common Stock                    108           568                                                676
Common Stock Dividends                                                  (387)                               (387)
Other                                                     (61)                                               (61)
                                                                                                          ------
                                                                                                           8,457
Comprehensive Income:
  Other Comprehensive Income,
   Net of Taxes
    Currency Translation Adjustment                                                          73               73
    Unrealized Loss on Cash Flow
      Hedges                                                                                (39)             (39)
   Net Income (Loss)                                                    (107)                               (107)
                                                                                                          -------
     Total Comprehensive Income                                                                              (73)
                                         ------        ------         ------               ----           ------

JUNE 30, 2002                            $2,261        $3,413         $2,802               $(92)          $8,384
                                         ======        ======         ======               ====           ======
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
                             AEP GENERATING COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

        Operating  revenues are derived  from the sale of Rockport  Plant energy
and capacity to two  affiliated  companies  pursuant to FERC approved  long-term
unit power agreements.  The unit power agreements  provide for recovery of costs
including a FERC  approved rate of return on common equity and a return on other
capital net of temporary cash investments.
        Net income declined  $345,000 or 17% for the second quarter and $432,000
or 11% for the  year-to-date  period  due to  limits  on  recovery  of return on
capital related to operating and in-service ratios of the Rockport Plant.
        Increased  recoverable  operating  expenses  resulted  in  a  $1,139,000
increase in operation  revenues for the second quarter.  A decrease in operating
revenues of $9,493,000 for the  year-to-date  period resulted from a decrease in
recoverable  expenses,  primarily fuel, as generation declined due to a decrease
in the Rockport Plant's  availability.  Outages for planned  maintenance at both
units in the first quarter of 2002 decreased Rockport Plant's generation.
        Operating expenses increased 3% in the second quarter and declined 8%
for the year-to-date period as follows:
<TABLE>
<CAPTION>
                                               Increase (Decrease)
                                               -------------------
                                 Second Quarter                 Year-to-Date
                                 --------------                 ------------
                                 (in thousands)      %          (in thousands)       %
                                 --------------      -          --------------       -
<S>                                     <C>        <C>               <C>           <C>
Fuel                                    $1,274       6               $(8,871)      (19)
Rent - Rockport Plant Unit 2              -          -                  -            -
Other Operation                          1,646      70                 1,910        36
Maintenance                             (1,593)    (40)                 (543)       (9)
Depreciation                                40       1                    87         1
Taxes Other Than Income Taxes             (118)    (12)                 (108)       (5)
Income Taxes                               268     N.M.               (1,550)      (62)
                                        ------                       -------
    Total                               $1,517       3               $(9,075)       (8)
                                        ======                       =======
</TABLE>
N.M. = Not Meaningful

        Fuel  expense  increased  in the second  quarter  due to an  increase in
generation and decreased due to the decline in generation  for the  year-to-date
period.
        The   increases  in  other   operation   expense  are primarily  due to
higher  costs  for  employee  benefits  and property insurance.
        Maintenance expense decreased  significantly  in the second quarter due
to scheduled  boiler inspection and repair being in the first  quarter  2002
verses  second  quarter  2001.  Maintenance  costs declines in both periods
reflect cost control  efforts.
        The decrease in income taxes  attributable to operations for the
year-to-date  period is primarily due to an over-accrual of state income  taxes
during first  quarter of 2001 based on an estimate of higher taxable income for
the year 2001 than actually  occurred.  The  over-accrual was adjusted
beginning in the second quarter of 2001 resulting in higher comparable income
taxes for the second quarter of 2002.
<PAGE>
        Interest  charges  declined  23% in the second  quarter  and 11% for the
year-to-date period due to lower interest rates on short-term  borrowing through
AEP's money pool reflecting market conditions and lower outstanding balances.
<PAGE>
<TABLE>
<CAPTION>
                             AEP GENERATING COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                     Three Months Ended June 30,                       Six Months Ended June 30,
                                                                 2002                 2001                 2002               2001
                                                                 ----                 ----                 ----               ----
                                                                                                     (in thousands)
<S>                                                            <C>                   <C>                 <C>               <C>
OPERATING REVENUES - Sales to
  AEP Affiliates                                               $53,356               $52,217             $103,231          $112,724
                                                               -------               -------             --------          --------

OPERATING EXPENSES:
   Fuel                                                         21,535                20,261               39,035            47,906
   Rent - Rockport Plant Unit 2                                 17,070                17,070               34,141            34,141
   Other Operation                                               4,014                 2,368                7,236             5,326
   Maintenance                                                   2,378                 3,971                5,354             5,897
   Depreciation                                                  5,642                 5,602               11,275            11,188
   Taxes Other Than Income Taxes                                   907                 1,025                1,960             2,068
   Income Taxes                                                    306                    38                  959             2,509
                                                               -------               -------             --------          --------

          TOTAL OPERATING EXPENSES                              51,852                50,335               99,960           109,035
                                                               -------               -------             --------          --------

OPERATING INCOME                                                 1,504                 1,882                3,271             3,689

NONOPERATING INCOME                                                 32                  -                      34              -

NONOPERATING EXPENSES                                               94                     1                  106                10

NONOPERATING INCOME TAX CREDITS                                    823                   888                1,655             1,759

INTEREST CHARGES                                                   547                   706                1,243             1,395
                                                               -------               -------             --------           -------

NET INCOME                                                     $ 1,718               $ 2,063             $  3,611           $ 4,043
                                                               =======               =======             ========           =======
</TABLE>
<TABLE>
<CAPTION>
                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                                    Three Months Ended June 30,                      Six Months Ended June 30,
                                                                 2002               2001                   2002             2001
                                                                 ----               ----                   ----             ----
                                                                                         (in thousands)
<S>                                                            <C>                 <C>                    <C>              <C>
BALANCE AT BEGINNING OF PERIOD                                 $14,604             $10,743                $13,761          $ 9,722

NET INCOME                                                       1,718               2,063                  3,611            4,043

CASH DIVIDENDS DECLARED                                          1,050                 959                  2,100            1,918
                                                               -------             -------                -------          -------

BALANCE AT END OF PERIOD                                       $15,272             $11,847                $15,272          $11,847
                                                               =======             =======                =======          =======
</TABLE>
The common stock of AEGCo is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                             AEP GENERATING COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                       June 30, 2002             December 31, 2001
                                                       -------------             -----------------
                                                                     (in thousands)
<S>                                                            <C>                           <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                                  $641,903                      $638,297
   General                                                        2,883                         3,012
   Construction Work in Progress                                 10,993                         6,945
                                                               --------                      --------
        Total Electric Utility Plant                            655,779                       648,254
   Accumulated Depreciation                                     349,825                       337,151
                                                               --------                      --------
           NET ELECTRIC UTILITY PLANT                           305,954                       311,103
                                                               --------                      --------

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

CURRENT ASSETS:
   Cash and Cash Equivalents                                       -                              983
   Accounts Receivable:
      Affiliated Companies                                       28,800                        22,344
      Miscellaneous                                                 147                           147
   Fuel - at average cost                                        19,157                        15,243
   Materials and Supplies - at average cost                       4,437                         4,480
   Prepayments                                                       86                           244
                                                               --------                      --------
           TOTAL CURRENT ASSETS                                  52,627                        43,441
                                                               --------                      --------

REGULATORY ASSETS                                                 5,089                         5,207
                                                               --------                      --------

DEFERRED CHARGES                                                  2,973                         1,471
                                                               --------                      --------

           TOTAL ASSETS                                        $366,762                      $361,341
                                                               ========                      ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                             AEP GENERATING COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                      June 30, 2002           December 31, 2001
                                                      -------------           -----------------
                                                                   (in thousands)
<S>                                                             <C>                       <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - Par Value $1,000:
      Authorized and Outstanding - 1,000 Shares                 $  1,000                  $  1,000
   Paid-in Capital                                                23,434                    23,434
   Retained Earnings                                              15,272                    13,761
                                                                --------                  --------
      Total Common Shareholder's Equity                           39,706                    38,195
   Long-term Debt                                                 44,798                    44,793
                                                                --------                  --------

        TOTAL CAPITALIZATION                                      84,504                    82,988
                                                                --------                  --------

OTHER NONCURRENT LIABILITIES                                         421                        76
                                                                --------                  --------

CURRENT LIABILITIES:
   Advances from Affiliates                                        9,775                    32,049
   Accounts Payable:
      General                                                      8,770                     7,582
      Affiliated Companies                                        29,867                     1,654
   Taxes Accrued                                                   8,592                     4,777
   Rent Accrued - Rockport Plant Unit 2                            4,963                     4,963
   Other                                                           3,641                     3,481
                                                                --------                  --------
        TOTAL CURRENT LIABILITIES                                 65,608                    54,506
                                                                --------                  --------

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
 PLANT UNIT 2                                                    113,832                   116,617
                                                                --------                  --------

REGULATORY LIABILITIES:
   Deferred Investment Tax Credit                                 54,635                    56,304
   Amounts Due to Customers for Income Taxes                      21,393                    22,725
                                                                --------                  --------
        TOTAL REGULATORY LIABILITIES                              76,028                    79,029
                                                                --------                  --------

DEFERRED INCOME TAXES                                             26,369                    27,975
                                                                --------                  --------

DEFERRED CREDITS                                                    -                          150
                                                                --------                  --------

CONTINGENCIES (Note 8)

        TOTAL CAPITALIZATION AND LIABILITIES                    $366,762                  $361,341
                                                                ========                  ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                             AEP GENERATING COMPANY
                            STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                       Six Months Ended June 30,
                                                                 2002                   2001
                                                                            (in thousands)
<S>                                                           <C>                     <C>
OPERATING ACTIVITIES:
   Net Income                                                 $  3,611                $  4,043
   Adjustment for Noncash Items:
     Depreciation                                               11,275                  11,188
     Deferred Income Taxes                                      (2,938)                 (2,935)
     Deferred Investment Tax Credits                            (1,669)                 (1,673)
     Amortization of Deferred Gain on Sale and Leaseback -
       Rockport Plant Unit 2                                    (2,785)                 (2,785)
     Deferred Property Taxes                                    (1,786)                 (1,829)
   Changes in Certain Current Assets and Liabilities:
     Accounts Receivable                                        (6,456)                  5,713
     Fuel, Materials and Supplies                               (3,871)                 (7,644)
     Accounts Payable                                           29,401                   6,852
     Taxes Accrued                                               3,815                   5,833
   Change in Other Assets                                           43                      (5)
   Change in Other Liabilities                                     355                  (2,366)
                                                              --------                --------

           Net Cash Flow From Operating Activities              28,995                  14,392
                                                              --------                --------

INVESTING ACTIVITIES - Construction Expenditures                (5,604)                 (1,537)
                                                              --------                --------

FINANCING ACTIVITIES:
     Change in Advances from Affiliates (net)                  (22,274)                (12,903)
     Dividends Paid                                             (2,100)                 (1,918)
                                                              --------                --------
           Net Cash Flows Used For Financing Activities        (24,374)                (14,821)
                                                              --------                --------

Net Increase in Cash and Cash Equivalents                         (983)                 (1,966)
Cash and Cash Equivalents at Beginning of Period                   983                   2,757
                                                              --------                --------
Cash and Cash Equivalents at End of Period                    $   -                   $    791
                                                              ========                ========
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized  amounts was $1,132,000 and $1,143,000
and  for  income  taxes  was   $1,217,000  and  $1,350,000  in  2002  and  2001,
respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

       APCo is a public  utility  engaged  in the  generation,  purchase,  sale,
transmission  and  distribution of electric power to 917,000 retail customers in
southwestern  Virginia and southern West  Virginia.  APCo as a member of the AEP
Power Pool shares in the revenues  and costs of the AEP Power  Pool's  wholesale
sales to neighboring utility systems and power marketers including power trading
transactions. APCo also sells wholesale power to municipalities.
       The cost of the AEP System's  generating  capacity is allocated among the
AEP Power Pool  members  based on their  relative  peak  demands and  generating
reserves  through the  payment of  capacity  charges and the receipt of capacity
credits. AEP Power Pool members are also compensated for the out-of-pocket costs
of energy  delivered to the AEP Power Pool and charged for energy  received from
the AEP Power Pool. The AEP Power Pool  calculates  each company's  prior twelve
month peak demand relative to the total peak demand of all member companies as a
basis for sharing  revenues and costs.  The result of this  calculation  is each
company's  member load ratio (MLR) which  determines  each company's  percentage
share of revenues and costs.

Critical Accounting Policies - Revenue Recognition
Regulatory   Accounting  -  As  a  result  of  our   cost-based   rate-regulated
transmission and distribution  operations,  our financial statements reflect the
actions  of  regulators  that can  result in the  recognition  of  revenues  and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities  (future revenue  reductions or refunds) are recorded to reflect the
economic effects of regulation by matching  expenses with their recovery through
regulated revenues in the same accounting period.
        When regulatory assets are probable of recovery through regulated rates,
we record  them as assets  on the  balance  sheet.  We test for  probability  of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation.  If we determine that recovery of a regulatory asset
is no longer  probable,  we write off that regulatory  asset as a charge against
net income.  A write off of regulatory  assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general expenses are recorded when incurred.


<PAGE>


Energy Marketing and Trading  Activities - AEP engages in wholesale  electricity
marketing  and  trading  transactions  (trading  activities).  A portion  of the
revenues and costs of AEP's trading activities are allocated to APCo as a member
of the AEP Power  Pool.  Trading  activities  involve the  purchase  and sale of
energy under  physical  forward  contracts at fixed and variable  prices and the
buying and selling of financial  energy  contracts which include exchange traded
futures and options and  over-the-counter  options and swaps.  Although  trading
contracts are generally short-term,  there are also long-term trading contracts.
We recognize revenues from trading activities  generally based on changes in the
fair value of open energy trading contracts.
           Recording the net change in the fair value of open trading  contracts
prior to settlement is commonly referred to as mark-to-market  (MTM) accounting.
Under MTM  accounting  the change in the  unrealized  gain or loss  throughout a
contract's  term is  recognized  in each  accounting  period.  When the contract
actually  settles,  that is,  the  energy  is  actually  delivered  in a sale or
received in a purchase or the parties  agree to forego  delivery and receipt and
net  settle in cash,  the  unrealized  gain or loss is  reversed  and the actual
realized cash gain or loss is recognized. Therefore, over the trading contract's
term an unrealized  gain or loss is recognized  as the  contract's  market value
changes.  When the  contract  settles the total gain or loss is realized in cash
but only the difference  between the accumulated  unrealized net gains or losses
recorded  in  prior  months  and the cash  proceeds  is  recognized.  Unrealized
mark-to-market  gains and losses are  included  in the  Balance  Sheet as energy
trading contract assets or liabilities.
           The majority of our trading  activities  represent  physical  forward
electricity  contracts  that are typically  settled by entering into  offsetting
contracts.  An example of our trading  activities is when, in January,  we enter
into a forward sales contract to deliver electricity in July. At the end of each
month  until the  contract  settles  in July,  we would  record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract  settles,  we would realize a gain or loss in
cash and reverse to revenues the previously recorded cumulative  unrealized gain
or loss.
           Depending on whether the  delivery  point for the  electricity  is in
AEP's  traditional  marketing  area or not  determines  where  the  contract  is
reported on APCo's income statement.  AEP's traditional  marketing area is up to
two  transmission  systems  from the AEP  service  territory.  Physical  forward
trading sale contracts with delivery points in AEP's traditional  marketing area
are included in revenues when the contracts  settle.  Physical  forward  trading
purchase contracts with delivery points in AEP's traditional  marketing area are
included in  purchased  power  expense when they  settle.  Prior to  settlement,
changes in the fair value of physical  forward  sale and  purchase  contracts in
AEP's  traditional  marketing  area are  included  in  revenues  on a net basis.
Physical  forward  sales  contracts  for delivery  outside of AEP's  traditional
marketing area are included in  nonoperating  income when the contract  settles.
Physical  forward purchase  contracts for delivery outside of AEP's  traditional
marketing area are included in nonoperating  expenses when the contract settles.
Prior to  settlement,  changes in the fair value of  physical  forward  sale and
purchase  contracts with delivery points outside of AEP's traditional  marketing
area are included in nonoperating income on a net basis.


<PAGE>


Results of Operations
        Net  income  increased  $10.2  million  or 28%  for the  quarter  due to
decreased  interest  charges and lower general  operating  expenses.  Net income
increased  $3.7  million or 4% for the  year-to-date  period due to decreases in
interest  charges offset in part by lower  wholesale  energy prices that reduced
margins.
        The following analyzes the changes in operating revenues:
<TABLE>
<CAPTION>
                                                    Increase (Decrease)
                                        Second Quarter               Year-to-Date
                                   (in millions)      %      (in millions)         %
                                                      -                            -
<S>                                     <C>        <C>           <C>             <C>
       Electricity Marketing
        and Trading Purchases           $(543)     (33)          $(1,059)        (31)
       Energy Delivery*                    (8)      (6)               (6)         (2)
       Sales to AEP Affiliates              5       12              -              -
                                        -----                    -------
            Total                       $(546)     (30)          $(1,065)        (28)
                                        =====                    =======
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.

        The decrease in revenues was due  primarily to reduced  sales by the AEP
Power Pool due to lower wholesale  energy prices.  In 2002 the wholesale  energy
sector has been under pressure from lower  commodity  prices in contrast to last
year when we had strong performance from the wholesale business due to favorable
market  conditions.  APCo,  as a member  of the AEP  Power  Pool,  shares in the
revenues and costs of wholesale  marketing and trading  activities  conducted on
its behalf by the AEP Power Pool.
        Energy  delivery  revenues  decreased  due  to the  continuing  economic
recession in 2002.
        The changes in the  components of operating  expenses were:
<TABLE>
<CAPTION>
                                                                        Increase (Decrease)
                                                                        -------------------
                                                     Second Quarter                          Year-to-Date
                                                 (in millions)           %             (in millions)            %
                                                                         -                                      -
<S>                                                      <C>           <C>               <C>                  <C>
       Fuel                                              $  22          26               $    34               19
       Electricity Marketing
        and Trading Purchases                             (543)        (38)               (1,016)             (35)
       Purchases from AEP Affiliates                       (27)        (32)                  (72)             (38)
       Other Operation                                      (4)         (6)                   (2)              (2)
       Maintenance                                          (6)        (18)                  (13)             (20)
       Depreciation and Amortization                         3           6                     6                7
       Taxes Other Than Income Taxes                        -            -                    (1)              (1)
       Income Taxes                                          3          15                   -                 -
                                                         -----                           --------
            Total                                        $(552)        (31)              $(1,064)             (29)
                                                         =====                           =======
</TABLE>
        Fuel  expense  increased  due to an increase in electric  generation  as
certain  plants  that  had  undergone  boiler  plant  maintenance  in 2001  were
available for service in 2002.
        The decline in  electricity  marketing and trading  purchases was mainly
due to reduced  prices caused by market  conditions  affecting  the  electricity
trading industry.
        Purchases from AEP affiliates  decreased due to the increase in internal
generation  as a result of certain  plants being  available  for service in 2002
that had undergone boiler plant maintenance in 2001.
        The decrease in other operations expense in the quarter is mainly due to
a decrease in transmission  equalization charges caused by a reduction in APCo's
MLR.
        The decrease in  maintenance  expense is primarily  due to the effect of
boiler plant maintenance performed on certain plants in 2001.
<PAGE>
        Depreciation and amortization expense increased predominantly due to the
additional  accelerated  amortization  beginning  in  July  2001  of  transition
regulatory  assets  in  connection  with  the  discontinuance  of SFAS 71 in the
Company's West Virginia jurisdiction whereby net  generation-related  regulatory
assets were transferred to the distribution portion of the business commensurate
with their recovery through  regulated rates (see Note 4 for further  discussion
of the effects of  restructuring).  Additional  investments in distribution  and
production   plant  also   contributed  to  the  increase  in  depreciation  and
amortization expense.
        The increase in income taxes from  operations for the quarter was due to
an increase in pre-tax operating income.
        Nonoperating income and expense decreased largely due to reduced margins
on electricity  trading outside of AEP's traditional marketing area caused by
market conditions affecting the electricity trading  industry in the second
quarter and by decreased  electricity  demand in the first quarter resulting
from mild weather and the slow economic recovery.
        The  decrease in interest  charges for the quarter was due to  increased
allowances for borrowed funds as a result of increased construction expenditures
and lower AEP money pool interest rates and balances. Interest charges decreased
for the year-to-date  period primarily due to increased  allowances for borrowed
funds as a result of increased  construction  expenditures,  the  retirement  of
first mortgage bonds on March 1, 2001 and lower AEP money pool interest rates.
<PAGE>
<TABLE>
<CAPTION>
                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                               Three Months Ended June 30,                Six Months Ended June 30,
                                                   2002                2001                2002               2001
                                                   ----                ----                ----               ----
                                                                          (in thousands)
<S>                                              <C>                <C>                 <C>               <C>
OPERATING REVENUES:
   Electricity Marketing and Trading             $1,113,871         $1,656,905          $2,371,226        $3,430,799
   Energy Delivery                                  139,475            147,924             294,470           300,021
   Sales to AEP Affiliates                           49,934             44,475              92,740            92,611
                                                 ----------         ----------          ----------        ----------
           TOTAL OPERATING REVENUES               1,303,280          1,849,304           2,758,436         3,823,431
                                                 ----------         ----------          ----------        ----------

OPERATING EXPENSES:
   Fuel                                             107,160             85,049             214,650           180,525
   Purchased Power:
     Electricity Marketing and Trading              885,469          1,427,844           1,891,068         2,907,372
     AEP Affiliates                                  58,717             85,987             119,497           191,661
   Other Operation                                   64,158             67,948             131,585           133,837
   Maintenance                                       27,638             33,842              53,489            66,851
   Depreciation and Amortization                     46,909             44,056              93,681            87,773
   Taxes Other Than Income Taxes                     25,050             25,257              50,045            50,685
   Income Taxes                                      22,955             19,959              57,643            57,213
                                                 ----------         ----------          ----------        ----------
           TOTAL OPERATING EXPENSES               1,238,056          1,789,942           2,611,658         3,675,917
                                                 ----------         ----------          ----------        ----------

OPERATING INCOME                                     65,224             59,362             146,778           147,514

NONOPERATING INCOME                                 422,518            649,030             822,690         1,114,435

NONOPERATING EXPENSES                               408,245            637,831             806,978         1,096,036

NONOPERATING INCOME TAX EXPENSE                       4,820              3,427               5,084             5,576

INTEREST CHARGES                                     28,069             30,715              55,457            62,131
                                                 ----------         ----------          ----------        ----------

NET INCOME                                           46,608             36,419             101,949            98,206

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

EARNINGS APPLICABLE TO COMMON STOCK              $   46,105         $   35,916          $  100,943        $   97,200
                                                 ==========         ==========          ==========        ==========
</TABLE>
<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)
                                           Three Months Ended June 30,                 Six Months Ended June 30,
                                             2002                   2001                2002               2001
                                             ----                   ----                ----               ----
                                                                       (in thousands)
<S>                                        <C>                    <C>                 <C>               <C>
NET INCOME                                 $46,608                $36,419             $101,949          $98,206

OTHER COMPREHENSIVE INCOME (LOSS):
  Cashflow Power Hedges                      2,217                   -                   2,217             -
  Cashflow Interest Rate Hedge              (2,128)                  -                  (2,128)            -
  Foreign Currency Exchange Rate
   Hedge                                      -                      (212)                 143             (629)
                                           -------                -------             --------          -------

COMPREHENSIVE INCOME                       $46,697                $36,207             $102,181          $97,577
                                           =======                =======             ========          =======
</TABLE>
The common stock of the Company is wholly owned by AEP.

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

                                           Three Months Ended June 30,                Six Months Ended June 30,
                                              2002                 2001                 2002               2001
                                              ----                 ----                 ----               ----
                                                                      (in thousands)
<S>                                         <C>                  <C>                  <C>               <C>
BALANCE AT BEGINNING OF PERIOD              $174,651             $149,469             $150,797          $120,584

NET INCOME                                    46,608               36,419              101,949            98,206
                                            --------             --------             --------          --------

DEDUCTIONS:
    Cash Dividends Declared:
      Common Stock                            30,984               32,398               61,968            64,797
      Preferred Stock                            360                  360                  721               721
    Capital Stock Expense                        142                  143                  284               285
                                            --------             --------             --------          --------

BALANCE AT END OF PERIOD                    $189,773             $152,987             $189,773          $152,987
                                            ========             ========             ========          ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                   June 30, 2002           December 31, 2001
                                                   -------------           -----------------
                                                                 (in thousands)
<S>                                                    <C>                          <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                          $2,107,053                   $2,093,532
   Transmission                                         1,215,707                    1,222,226
   Distribution                                         1,910,496                    1,887,020
   General                                                258,731                      257,957
   Construction Work in Progress                          288,146                      203,922
                                                       ----------                   ----------
        Total Electric Utility Plant                    5,780,133                    5,664,657
   Accumulated Depreciation and Amortization            2,370,959                    2,296,481
                                                       ----------                   ----------
        NET ELECTRIC UTILITY PLANT                      3,409,174                    3,368,176
                                                       ----------                   ----------

OTHER PROPERTY AND INVESTMENTS                             51,886                       53,736
                                                       ----------                   ----------

LONG-TERM ENERGY TRADING CONTRACTS                        490,983                      316,249
                                                       ----------                   ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                1,304                       13,663
   Advances to Affiliates                                  95,498                         -
   Accounts Receivable:
      Customers                                           130,219                      113,371
      Affiliated Companies                                204,490                       63,368
      Miscellaneous                                        22,598                       11,847
      Allowance for Uncollectible Accounts                 (2,096)                      (1,877)
   Fuel - at average cost                                  38,902                       56,699
   Materials and Supplies - at average cost                57,262                       59,849
   Accrued Utility Revenues                                22,919                       30,907
   Energy Trading Contracts                               794,212                      566,284
   Prepayments and Other                                   29,359                       16,018
                                                       ----------                   ----------
        TOTAL CURRENT ASSETS                            1,394,667                      930,129
                                                       ----------                   ----------

REGULATORY ASSETS                                         387,785                      397,383
                                                       ----------                   ----------

DEFERRED CHARGES                                           42,867                       42,265
                                                       ----------                   ----------

        TOTAL ASSETS                                   $5,777,362                   $5,107,938
                                                       ==========                   ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)
                                                          June 30, 2002           December 31, 2001
                                                          -------------           -----------------
                                                                     (in thousands)
<S>                                                             <C>                       <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 30,000,000 Shares
      Outstanding - 13,499,500 Shares                           $  260,458                $  260,458
   Paid-in Capital                                                 716,071                   715,786
   Accumulated Other Comprehensive Income (Loss)                      (108)                     (340)
   Retained Earnings                                               189,773                   150,797
                                                                ----------                ----------
        Total Common Shareowner's Equity                         1,166,194                 1,126,701
   Cumulative Preferred Stock:
      Not Subject to Mandatory Redemption                           17,790                    17,790
      Subject to Mandatory Redemption                               10,860                    10,860
   Long-term Debt                                                1,690,024                 1,476,552
                                                                ----------                ----------

           TOTAL CAPITALIZATION                                  2,884,868                 2,631,903
                                                                ----------                ----------

OTHER NONCURRENT LIABILITIES                                        86,148                    84,104
                                                                ----------                ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                              315,007                    80,007
   Advances from Affiliates                                           -                      291,817
   Accounts Payable - General                                      126,032                   131,387
   Accounts Payable - Affiliated Companies                         142,918                    84,518
   Taxes Accrued                                                    90,827                    55,583
   Customer Deposits                                                20,113                    13,177
   Interest Accrued                                                 28,180                    21,770
   Energy Trading Contracts                                        760,856                   549,703
   Other                                                            65,784                    75,299
                                                                ----------                ----------

           TOTAL CURRENT LIABILITIES                             1,549,717                 1,303,261
                                                                ----------                ----------

DEFERRED INCOME TAXES                                              696,835                   703,575
                                                                ----------                ----------

DEFERRED INVESTMENT TAX CREDITS                                     36,132                    38,328
                                                                ----------                ----------

LONG-TERM ENERGY TRADING CONTRACTS                                 432,097                   257,129
                                                                ----------                ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                         91,565                    89,638
                                                                ----------                ----------

CONTINGENCIES (Note 8)

        TOTAL CAPITALIZATION AND LIABILITIES                    $5,777,362                $5,107,938
                                                                ==========                ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                         Six Months Ended June 30,
                                                                      2002                    2001
                                                                          (in thousands)
<S>                                                              <C>                       <C>
OPERATING ACTIVITIES:
   Net Income                                                    $ 101,949                 $  98,206
   Adjustments for Noncash Items:
      Depreciation and Amortization                                 93,737                    87,829
      Deferred Income Taxes                                         (7,055)                   31,726
      Deferred Investment Tax Credits                               (2,196)                   (2,212)
      Mark-to-Market Energy Trading Contracts                      (12,797)                  (97,010)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                   (168,502)                   69,776
      Fuel, Materials and Supplies                                  20,384                    (4,859)
      Accrued Utility Revenues                                       7,988                    48,007
      Accounts Payable                                              53,045                    (3,747)
      Taxes Accrued                                                 35,244                    10,438
      Interest Accrued                                               6,410                     5,924
   Change in Other Assets                                          (13,851)                   22,683
   Change in Other Liabilities                                       7,449                   (39,002)
                                                                 ---------                 ---------
           Net Cash Flows From Operating Activities                121,805                   227,759
                                                                 ---------                 ---------

INVESTING ACTIVITIES:
      Construction Expenditures                                   (128,853)                 (107,876)
      Proceeds from Sale of Property                                   583                     1,182
                                                                 ---------                 ---------
           Net Cash Flows Used For Investing Activities           (128,270)                 (106,694)
                                                                 ---------                 ---------

FINANCING ACTIVITIES:
      Change in Short-term Debt (net)                                 -                     (191,495)
      Change in Advances to Affiliates (net)                      (387,315)                  310,277
      Issuance of Long-term Debt                                   444,110                      -
      Retirement of Long-term Debt                                    -                     (175,000)
      Dividends Paid on Common Stock                               (61,968)                  (64,797)
      Dividends Paid on Cumulative Preferred Stock                    (721)                     (721)
                                                                 ---------                 ---------
           Net Cash Flows Used For Financing Activities             (5,894)                 (121,736)
                                                                 ---------                 ---------

Net Decrease in Cash and Cash Equivalents                          (12,359)                     (671)
Cash and Cash Equivalents at Beginning of Period                    13,663                     5,847
                                                                  --------                 ---------
Cash and Cash Equivalents at End of Period                        $  1,304                 $   5,176
                                                                  ========                 =========
</TABLE>
Supplemental Disclosure:
Cash  paid  for  interest  net  of  capitalized   amounts  was  $47,676,000  and
$54,957,000  and for income taxes was  $36,585,000  and  $17,064,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $1,684,000 in
2001, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

       CPL is a public utility engaged in the generation, sale, transmission and
distribution of electric power in southern Texas.  CPL also sells electric power
at wholesale to other utilities, municipalities, rural electric cooperatives and
beginning  in  2002  to  retail  electric   providers  (REPs)  in  Texas,   (see
"Introduction of Customer Choice" section below).
       Wholesale power  marketing and trading  activities are conducted on CPL's
behalf by AEPSC. CPL, along with the other AEP electric operating  subsidiaries,
shares in AEP's forward trades with other utility systems and power marketers.

Introduction of Customer Choice
       On January 1, 2002, customer choice of electricity  supplier began in the
Electric  Reliability  Council of Texas  (ERCOT)  area of Texas.  CPL  currently
operates in the ERCOT region of Texas.
       Under the Texas  Restructuring  Legislation,  each  electric  utility was
required to submit a plan to  structurally  unbundle its business  into a retail
electric  provider,  a power  generator,  and a  transmission  and  distribution
utility.  During the year 2000,  CPL  submitted a plan for  separation  that was
subsequently  approved  by the PUCT.  As a result of this  legislation,  CPL has
functionally  separated its generation from its  transmission  and  distribution
operations  and formed a separate REP.  Pending  regulatory  approval,  CPL will
corporately  separate its  generation  from its  transmission  and  distribution
operations.  The REP is a separate  legal entity that is a subsidiary of AEP and
is not owned by or consolidated with CPL.
       Since the REP is the  electricity  supplier  to retail  customers  in the
ERCOT area,  CPL sells its generation to the REP and provides  transmission  and
distribution  services to retail customers in its ERCOT service territory.  As a
result of the formation of the REP, CPL no longer supplies electricity to retail
customers in the ERCOT area.  Instead CPL sells its  generation  to the REP. The
implementation of REPs as suppliers to retail customers has caused a significant
shift in CPL's sales as described below under "Results of Operations."

Critical Accounting Policies - Revenue Recognition
Regulatory   Accounting  -  As  a  result  of  our   cost-based   rate-regulated
transmission and distribution  operations,  our financial statements reflect the
actions  of  regulators  that can  result in the  recognition  of  revenues  and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities  (future revenue  reductions or refunds) are recorded to reflect the
economic effects of regulation by matching  expenses with their recovery through
regulated revenues in the same accounting period.


<PAGE>


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

Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general, expenses are recorded when incurred.

Energy Marketing and Trading  Activities - AEP engages in wholesale  electricity
marketing  and  trading  transactions  (trading  activities).  A portion  of the
revenues and costs of AEP's trading  activities  are  allocated to CPL.  Trading
activities  allocated  to CPL  involve  the  purchase  and sale of energy  under
physical  forward  contracts  at fixed and  variable  prices.  Although  trading
contracts are generally short-term,  there are also long-term trading contracts.
We recognize revenues from trading activities  generally based on changes in the
fair value of open energy trading contracts.
           Recording the net change in the fair value of open trading  contracts
as revenues prior to settlement is commonly referred to as mark-to-market  (MTM)
accounting.  Under MTM  accounting  the  change in the  unrealized  gain or loss
throughout a contract's term is recognized in each accounting  period.  When the
contract actually settles,  that is, the energy is actually  delivered in a sale
or received in a purchase or the parties agree to forego delivery and receipt of
electricity  and net settle in cash, the unrealized gain or loss is reversed out
of revenues and the actual  realized cash gain or loss is recognized in revenues
for a sale or in purchased  power  expense for a purchase.  Therefore,  over the
trading  contract's  term  an  unrealized  gain or  loss  is  recognized  as the
contract's  market value  changes.  When the contract  settles the total gain or
loss is  realized  in cash but  only  the  difference  between  the  accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized.  Unrealized  mark-to-market  gains and  losses are  included  in the
balance sheet as energy trading contract assets or liabilities.
        Our trading activities represent physical forward electricity  contracts
that are typically settled by entering into offsetting contracts.  An example of
our  trading  activities  is when,  in  January,  we enter into a forward  sales
contract  to deliver  electricity  in July.  At the end of each month  until the
contract  settles in July, we would record our share of any  difference  between
the  contract  price  and the  market  price  as an  unrealized  gain or loss in
revenues.  In July when the contract  settles,  we would  realize our share of a
gain or loss in cash and reverse to revenues the previously  recorded cumulative
unrealized  gain or loss.  Prior to settlement,  the change in the fair value of
physical  forward sale and  purchase  contracts is included in revenues on a net
basis.  Upon  settlement of a forward trading  contract,  the amount realized is
included in revenues for a sales  contract and the realized  cost is included in
purchased  power  expense  for a  purchase  contract  with the  prior  change in
unrealized fair value reversed in revenues.

<PAGE>

        Continuing  with the above  example,  assume  that  later in  January or
sometime in February  through July we enter into an offsetting  forward contract
to buy  electricity  in July. If we do nothing else with these  contracts  until
settlement in July and if the volumes,  delivery  point,  schedule and other key
terms match then the  difference  between the sale price and the purchase  price
represents a fixed value to be realized  when the  contracts  settle in July. If
the purchase  contract is perfectly  matched  with the sales  contract,  we have
effectively fixed the profit or loss;  specifically it is the difference between
the contracted settlement price of the two contracts.  Mark-to-market accounting
for these  contracts  from this point  forward  will have no  further  impact on
results of operations  but will have an  offsetting  and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase  contract prior to entering into a sales contract.  If
the sale and  purchase  contracts do not match  exactly as to volumes,  delivery
point,   schedule  and  other  key  terms,   then  there  could  be   continuing
mark-to-market  effects on revenues from  recording  additional  changes in fair
values using mark-to-market accounting.
        The  fair  value  of open  short-term  trading  contracts  are  based on
exchange  prices and broker quotes.  We  mark-to-market  open long-term  trading
contracts based mainly on AEP-developed  valuation models. These models estimate
future energy  prices based on existing  market and broker quotes and supply and
demand market data and  assumptions.  The fair values  determined are reduced by
reserves to adjust for credit risk and liquidity  risk.  Credit risk is the risk
that the  counterparty  to the  contract  will  fail to  perform  or fail to pay
amounts due AEP.  Liquidity risk represents the risk that  imperfections  in the
market  will cause the price to be less than or more than what the price  should
be based purely on supply and demand.  There are inherent  risks  related to the
underlying  assumptions  in  models  used to  determine  the fair  value of open
long-term  trading  contracts.  AEP has  independent  controls to  evaluate  the
reasonableness  of our valuation  models.  However,  energy markets,  especially
electricity  markets,  are imperfect and volatile and unforeseen  events can and
will cause  reasonable  price curves to differ from actual  prices  throughout a
contract's term and when contracts settle. Therefore, there could be significant
adverse or favorable  effects on future  results of operations and cash flows if
market  prices at  settlement  do not  correlate  with the  AEP-developed  price
models.
       Volatility in commodities  markets  affects the fair values of all of our
open trading  contracts  exposing CPL to market risk. See the  "Quantitative and
Qualitative  Disclosure  About  Market  Risk"  section  of Part I,  Item 2 for a
discussion of the policies and procedures  used to manage  exposure to risk from
trading activities.



<PAGE>


Results of Operations
         Second  quarter  net income  decreased  $19  million or 36%,  while the
year-to-date  net income  decreased  $30 million or 34%  primarily due to a slow
economic recovery, a significant decline in wholesale prices and the replacement
of sales to ultimate retail  customers with sales to the REP's in the ERCOT area
beginning on January 1, 2002.  Operating revenues decreased $171 million for the
quarter and $371 million year-to-date as shown below:
<TABLE>
<CAPTION>
                                                              Increase (Decrease)
                                             Second Quarter                              Year-to-Date
                                      (in millions)           %                    (in millions)        %
                                                              -                                         -
<S>                                          <C>            <C>                      <C>              <C>
       Electricity Marketing
        and Trading*                         $(390)         (83)                     $(751)           (80)
       Energy Delivery*                          8            5                         10              4
       Sales to AEP Affiliates                 211          N.M.                       370            N.M.
                                             -----                                   -----
            Total                            $(171)         (26)                     $(371)           (30)
                                             =====                                   =====
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.

       N.M. = Not Meaningful

        Electricity  marketing and trading revenues decreased as a result of the
  elimination  of retail  sales in the ERCOT  area as of  January  1, 2002 and a
  decrease in energy trading. In 2002 the wholesale energy sector has been under
  pressure  from lower  commodity  prices in  contrast  to last year when we had
  strong  performance  from  the  wholesale  business  due to  favorable  market
  conditions.  Revenues from sales to AEP affiliates rose  substantially  due to
  the supplying of electricity to the newly formed affiliated REP's.Although CPL
  sold electricity to the affiliated REP instead of directly to retail customers
  in the ERCOT area,  total  revenues  received  were lower because of the lower
  wholesale prices.
        Operating  expenses  declined 27% for the quarter and 31%  year-to-date.
  The changes in the  components of operating expenses were:
<TABLE>
<CAPTION>
                                                                Increase (Decrease)
                                                 Second Quarter                        Year-to-Date
                                          (in millions)            %              (in millions)        %
                                                                   -                                   -
<S>                                              <C>             <C>               <C>                <C>
       Fuel                                      $ (57)          (39)              $(155)             (52)
       Electricity Marketing
        and Trading Purchases                      (84)          (40)               (157)             (38)
       Purchases from AEP Affiliates                (1)          (11)                 (6)             (24)
       Other Operation                              (4)           (6)                (13)              (9)
       Maintenance                                  (3)          (18)                (10)             (27)
       Depreciation and Amortization                 7            14                   7                7
       Taxes Other Than Income Taxes                 6            35                  15               40
       Income Taxes                                (17)          (50)                (25)             (48)
                                                 -----                             -----
            Total                                $(153)          (27)              $(344)             (31)
                                                 =====                             =====
</TABLE>
         Fuel  expense  decreased  due to a decrease in the average unit cost of
fuel resulting from lower spot market natural gas prices.
         Electricity  marketing and trading purchases decreased due to a decline
in demand for electricity  and lower  wholesale  prices due to the slow economic
recovery.
         The decrease in maintenance and other operation  expenses resulted from
the effects of a STP nuclear plant refueling outage in 2001.


<PAGE>


         Taxes  other  than  income  taxes  increased  due  to the  effect  of a
favorable accrual adjustment in 2001 for ad valorem taxes.
         The decrease in income tax expense  attributable to operations in 2002
was primarily due to a decrease in pre-tax operating income.


<PAGE>
<TABLE>
<CAPTION>
                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                          Three Months Ended June 30,        Six Months Ended June 30,
                                                        2002                  2001              2002                2001
                                                        ----                  ----              ----                ----
                                                                              (in thousands)
<S>                                                  <C>                 <C>                 <C>               <C>
OPERATING REVENUES:
    Electricity Marketing and Trading                $ 77,617            $  468,428          $ 189,052         $  940,722
    Energy Delivery                                   176,828               168,433            288,955            278,763
    Sales to AEP Affiliates                           223,092                11,638            402,753             32,426
                                                     --------            ----------          ---------         ----------

           TOTAL OPERATING REVENUES                   477,537               648,499            880,760          1,251,911
                                                     --------            ----------          ---------         ----------

OPERATING EXPENSES:
   Fuel                                                89,956               147,179            144,284            299,032
   Purchased Power:
      Electricity Marketing and Trading               123,118               206,733            251,443            408,529
      Affiliates                                       12,564                14,039             20,491             26,809
   Other Operation                                     71,975                76,189            137,961            151,260
   Maintenance                                         14,782                17,995             25,741             35,282
   Depreciation and Amortization                       60,923                53,587            102,770             95,978
   Taxes Other Than Income Taxes                       23,474                17,330             51,396             36,818
   Income Taxes                                        16,426                33,096             26,910             51,700
                                                     --------            ----------          ---------         ----------

           TOTAL OPERATING EXPENSES                   413,218               566,148            760,996          1,105,408
                                                     --------            ----------          ---------         ----------

OPERATING INCOME                                       64,319                82,351            119,764            146,503

NONOPERATING INCOME (LOSS)                              4,472                  (697)            14,003              2,502

NONOPERATING EXPENSES                                   3,478                   810             12,865              1,647

NONOPERATING INCOME TAX EXPENSE (CREDIT)                 (648)                   34               (515)               757

INTEREST CHARGES                                       32,426                28,292             63,437             59,052
                                                     --------            ----------          ---------         ----------

NET INCOME                                             33,535                52,518             57,980             87,549

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

EARNINGS APPLICABLE TO COMMON STOCK                  $ 33,474            $   52.457          $  57,859         $   87,428
                                                     ========            ==========          =========         ==========
</TABLE>
<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                         Three Months Ended June 30,             Six Months Ended June 30,
                                     2002                     2001                  2002              2001
                                     ----                     ----                  ----              ----
                                                             (in thousands)
<S>                                <C>                      <C>                   <C>              <C>
NET INCOME                         $33,535                  $52,518               $57,980          $87,549

OTHER COMPREHENSIVE INCOME
    Cash Flow Power Hedge              263                     -                      263             -
                                   -------                  -------               -------          -------

COMPREHENSIVE INCOME               $33,798                  $52,518               $58,243          $87,549
                                   =======                  =======               =======          =======
</TABLE>
The  common  stock of CP&L is  wholly  owned  by AEP.  See  Notes  to  Financial
Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                           Three Months Ended June 30,                 Six Months Ended June 30,
                                       2002                     2001                  2002              2001
                                       ----                     ----                  ----              ----
                                                               (in thousands)
<S>                                  <C>                      <C>                   <C>              <C>
BALANCE AT BEGINNING OF PERIOD       $812,080                 $790,176              $826,197         $792,219
NET INCOME                             33,535                   52,518                57,980           87,549
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                       38,502                   37,014                77,004           74,028
    Preferred Stock                        61                       61                   121              121
                                     --------                 --------              --------         --------

BALANCE AT END OF PERIOD             $807,052                 $805,619              $807,052         $805,619
                                     ========                 ========              ========         ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                       June 30, 2002            December 31, 2001
                                                       -------------            -----------------
                                                                       (in thousands)
<S>                                                         <C>                         <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                               $3,175,010                  $3,169,421
   Transmission                                                698,909                     663,655
   Distribution                                              1,301,563                   1,279,037
   General                                                     243,438                     241,137
   Construction Work in Progress                               158,562                     169,075
   Nuclear Fuel                                                251,157                     247,382
                                                            ----------                  ----------
        Total Electric Utility Plant                         5,828,639                   5,769,707
   Accumulated Depreciation and Amortization                 2,518,016                   2,446,027
                                                            ----------                  ----------
      NET ELECTRIC UTILITY PLANT                             3,310,623                   3,323,680
                                                            ----------                  ----------

OTHER PROPERTY AND INVESTMENTS                                  50,005                      47,950
                                                            ----------                  ----------

SECURITIZED TRANSITION ASSET                                   750,939                        -
                                                            ----------                  ----------

LONG-TERM ENERGY TRADING CONTRACTS                              31,136                      72,502
                                                            ----------                  ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                    28,385                      10,909
   Accounts Receivable:
      General                                                   87,683                      38,459
      Affiliated Companies                                     228,135                       6,249
      Allowance for Uncollectible Accounts                        (505)                       (186)
   Fuel Inventory - at LIFO cost                                42,997                      38,690
   Materials and Supplies - at average cost                     52,239                      55,475
   Energy Trading Contracts                                     64,633                     212,979
   Prepayments and Other Current Assets                          5,432                       2,742
                                                            ----------                  ----------
      TOTAL CURRENT ASSETS                                     508,999                     365,317
                                                            ----------                  ----------

REGULATORY ASSETS                                              227,100                     226,806
                                                            ----------                  ----------

REGULATORY ASSETS DESIGNATED FOR SECURITIZATION                171,066                     959,294
                                                            ----------                  ----------

NUCLEAR DECOMMISSIONING TRUST FUND                              97,429                      98,600
                                                            ----------                  ----------

DEFERRED CHARGES                                                89,202                      21,837
                                                            ----------                  ----------

     TOTAL ASSETS                                           $5,236,499                  $5,115,986
                                                            ==========                  ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                                      June 30, 2002           December 31, 2001
                                                                      -------------           -----------------
                                                                                        (in thousands)
<S>                                                                           <C>                         <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - $25 Par Value:
      Authorized - 12,000,000 Shares
      Outstanding - 2,211,678 Shares at June 30, 2002
                          6,755,535 Shares at December 31, 2001               $   55,292                  $  168,888
   Paid-in Capital                                                               132,592                     405,000
   Accumulated Other Comprehensive Income                                            263                        -
   Retained Earnings                                                             807,052                     826,197
                                                                              ----------                  ----------
        Total Common Shareowner's Equity                                         995,199                   1,400,085
   Preferred Stock                                                                 5,967                       5,967
   CPL - Obligated, Mandatorily Redeemable Preferred
     Securities of Subsidiary Trust Holding Solely
     Junior Subordinated Debentures of CPL                                       136,250                     136,250
   Long-term Debt                                                              1,704,374                     988,768
                                                                              ----------                  ----------

           TOTAL CAPITALIZATION                                                2,841,790                   2,531,070
                                                                              ----------                  ----------

CURRENT LIABILITIES:
   Short-term Debt Affiliate                                                     200,000                        -
   Long-term Debt Due Within One Year                                            196,017                     265,000
   Advances from Affiliates                                                      102,285                     354,277
   Accounts Payable - General                                                     66,204                      65,307
   Accounts Payable - Affiliated Companies                                       155,097                      49,301
   Customer Deposits                                                                 555                      26,744
   Over Recovered Fuel                                                            61,867                      57,762
   Taxes Accrued                                                                 109,163                      83,512
   Interest Accrued                                                               25,606                      18,524
   Energy Trading Contracts                                                       67,321                     219,486
   Other                                                                          23,009                      22,768
                                                                              ----------                  ----------

           TOTAL CURRENT LIABILITIES                                           1,007,124                   1,162,681
                                                                              ----------                  ----------

DEFERRED INCOME TAXES                                                          1,147,562                   1,163,795
                                                                              ----------                  ----------

DEFERRED INVESTMENT TAX CREDITS                                                  120,289                     122,892
                                                                              ----------                  ----------

LONG-TERM ENERGY TRADING CONTRACTS                                                28,118                      62,138
                                                                              ----------                  ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                       91,616                      73,410
                                                                              ----------                  ----------

CONTINGENCIES (Note 8)

           TOTAL CAPITALIZATION AND LIABILITIES                               $5,236,499                  $5,115,986
                                                                              ==========                  ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                                 Six Months Ended June 30,
                                                                             2002                  2001
                                                                             ----                  ----
                                                                                       (in thousands)
<S>                                                                    <C>                       <C>
OPERATING ACTIVITIES:
   Net Income                                                          $  57,980                 $  87,549
   Adjustments for Noncash Items:
      Depreciation and Amortization                                      102,770                    95,978
      Deferred Income Taxes                                              (18,103)                  (17,699)
      Deferred Investment Tax Credits                                     (2,603)                   (2,604)
      Deferred Property Taxes                                            (19,120)                  (21,563)
      Mark-to-Market Energy Trading Contracts                              3,932                    (8,338)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                         (270,791)                   47,588
      Fuel, Materials and Supplies                                        (1,071)                  (17,688)
      Fuel Recovery                                                        4,105                    33,954
      Accounts Payable                                                   106,693                   (27,530)
      Taxes Accrued                                                       25,651                    73,457
   Change in Other Assets                                                (38,746)                  (13,442)
   Change in Other Liabilities                                              (566)                    4,152
                                                                       ---------                 ---------
           Net Cash Flows From (Used For) Operating Activities           (49,869)                  233,814
                                                                       ---------                 ---------

INVESTING ACTIVITIES:
      Construction Expenditures                                          (64,147)                 (109,638)
      Other                                                                 -                         (354)
                                                                       ---------                 ---------
           Net Cash Flows Used For Investing Activities                  (64,147)                 (109,992)
                                                                       ---------                 ----------

FINANCING ACTIVITIES:
      Issuance of Long-term Debt                                         796,613                      -
      Retirement of Long-term Debt                                      (150,000)                  (11,971)
      Change in Short-term Debt Affiliated (net)                         200,000                      -
      Retirement of Common Stock                                        (386,004)                     -
      Change in Advances from Affiliates (net)                          (251,992)                  (46,200)
      Dividends Paid on Common Stock                                     (77,004)                  (74,028)
      Dividends Paid on Cumulative Preferred Stock                          (121)                     (121)
                                                                       ---------                 ---------
           Net Cash Flows From (Used For) Financing Activities           131,492                  (132,320)
                                                                       ---------                 ---------

Net Decrease in Cash and Cash Equivalents                                 17,476                    (8,498)
Cash and Cash Equivalents at Beginning of Period                          10,909                    14,253
                                                                       ---------                 ---------
Cash and Cash Equivalents at End of Period                             $  28,385                 $   5,755
                                                                       =========                 =========
</TABLE>
Supplemental Disclosure:
Cash  paid  for  interest  net  of  capitalized   amounts  was  $40,588,000  and
$46,083,000  and for income taxes was  $44,322,000  and  $11,307,000 in 2002 and
2001, respectively.

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

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

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

      Columbus  Southern  Power  Company  is a  public  utility  engaged  in the
generation,  purchase,  sale, transmission and distribution of electric power to
678,000 retail  customers in central and southern Ohio. CSPCo as a member of the
AEP  Power  Pool  shares  in the  revenues  and  costs of the AEP  Power  Pool's
wholesale sales to neighboring  utility  systems and power  marketers  including
power trading transactions. CSPCo also sells wholesale power to municipalities.
      The cost of the AEP Power Pool's  generating  capacity is allocated  among
the Pool members based on their  relative peak demands and  generating  reserves
through  the payment of capacity  charges and receipt of capacity  credits.  AEP
Power Pool members are also compensated for their  out-of-pocket costs of energy
delivered  to the AEP Power Pool and  charged for energy  received  from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member  companies as a basis for
sharing AEP Power Pool revenues and costs. The result of this calculation is the
member load ratio (MLR) which determines each company's  percentage share of AEP
Power Pool revenues and costs.

Critical Accounting Policies - Revenue Recognition
Regulatory   Accounting  -  As  a  result  of  our   cost-based   rate-regulated
transmission and distribution  operations,  our financial statements reflect the
actions  of  regulators  that can  result in the  recognition  of  revenues  and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities  (future revenue  reductions or refunds) are recorded to reflect the
economic effects of regulation by matching  expenses with their recovery through
regulated revenues in the same accounting period.
         When  regulatory  assets are  probable  of recovery  through  regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation.  If we determine that recovery of a regulatory asset
is no longer  probable,  we write off that regulatory  asset as a charge against
net income.  A write off of regulatory  assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general expenses are recorded when incurred.

<PAGE>

Energy Marketing and Trading  Activities - AEP engages in wholesale  electricity
marketing  and  trading  transactions  (trading  activities).  A portion  of the
revenues  and costs of AEP's  trading  activities  are  allocated  to CSPCo as a
member of the AEP Power Pool.  Trading  activities involve the purchase and sale
of energy under physical forward  contracts at fixed and variable prices and the
buying and selling of financial  energy  contracts which include exchange traded
futures and options and  over-the-counter  options and swaps.  Although  trading
contracts are generally short-term,  there are also long-term trading contracts.
We recognize revenues from trading activities  generally based on changes in the
fair value of open energy trading contracts.
           Recording the net change in the fair value of open trading  contracts
prior to settlement is commonly referred to as mark-to-market  (MTM) accounting.
Under MTM  accounting  the change in the  unrealized  gain or loss  throughout a
contract's  term is  recognized  in each  accounting  period.  When the contract
actually  settles,  that is,  the  energy  is  actually  delivered  in a sale or
received in a purchase or the parties  agree to forego  delivery and receipt and
net  settle in cash,  the  unrealized  gain or loss is  reversed  and the actual
realized cash gain or loss is recognized. Therefore, over the trading contract's
term an unrealized  gain or loss is recognized  as the  contract's  market value
changes.  When the  contract  settles the total gain or loss is realized in cash
but only the difference  between the accumulated  unrealized net gains or losses
recorded  in  prior  months  and the cash  proceeds  is  recognized.  Unrealized
mark-to-market  gains and losses are  included  in the  Balance  Sheet as energy
trading contract assets or liabilities.
           The majority of our trading  activities  represent  physical  forward
electricity  contracts  that are typically  settled by entering into  offsetting
contracts.  An example of our trading  activities is when, in January,  we enter
into a forward sales contract to deliver electricity in July. At the end of each
month  until the  contract  settles  in July,  we would  record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of a gain
or loss in cash and reverse the previously recorded  cumulative  unrealized gain
or loss.
           Depending on whether the  delivery  point for the  electricity  is in
AEP's  traditional  marketing  area or not  determines  where  the  contract  is
reported on CSPCo's income statement.  AEP's traditional marketing area is up to
two  transmission  systems  from the AEP  service  territory.  Physical  forward
trading sale contracts with delivery points in AEP's traditional  marketing area
are included in revenues when the contracts  settle.  Physical  forward  trading
purchase contracts with delivery points in AEP's traditional  marketing area are
included in  purchased  power  expense when they  settle.  Prior to  settlement,
changes in the fair value of physical  forward  sale and  purchase  contracts in
AEP's  traditional  marketing  area are  included  in  revenues  on a net basis.
Physical  forward  sales  contracts  for delivery  outside of AEP's  traditional
marketing area are included in  nonoperating  income when the contract  settles.
Physical  forward purchase  contracts for delivery outside of AEP's  traditional
marketing area are included in nonoperating  expenses when the contract settles.
Prior to  settlement,  changes in the fair value of  physical  forward  sale and
purchase  contracts with delivery points outside of AEP's traditional  marketing
area are included in nonoperating income on a net basis.
        Continuing  with the above  example,  assume  that  later in  January or
sometime in February  through July we enter into an offsetting  forward contract
to buy  electricity  in July. If we do nothing else with these  contracts  until
<PAGE>
settlement in July and if the volumes,  delivery  point,  schedule and other key
terms match then the  difference  between the sale price and the purchase  price
represents a fixed value to be realized  when the  contracts  settle in July. If
the purchase  contract is perfectly  matched  with the sales  contract,  we have
effectively fixed the profit or loss;  specifically it is the difference between
the contracted settlement price of the two contracts.  Mark-to-market accounting
for these  contracts  from this point  forward  will have no  further  impact on
results of operations  but will have an  offsetting  and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase  contract prior to entering into a sales contract.  If
the sale and  purchase  contracts do not match  exactly as to volumes,  delivery
point,   schedule  and  other  key  terms,   then  there  could  be   continuing
mark-to-market  effects on  results  of  operations  from  recording  additional
changes in fair values using mark-to-market accounting.
        Trading of electricity options,  futures and swaps, represents financial
transactions  with  unrealized  gains and losses  from  changes  in fair  values
reported net in  nonoperating  income  until the  contracts  settle.  When these
financial  contracts  settle,  we  record  our  share  of the  net  proceeds  in
nonoperating  income and  reverse to  nonoperating  income the prior  cumulative
unrealized net gain or loss.
        The  fair  value  of open  short-term  trading  contracts  are  based on
exchange  prices and broker quotes.  We  mark-to-market  open long-term  trading
contracts based mainly on AEP-developed  valuation models. These models estimate
future energy  prices based on existing  market and broker quotes and supply and
demand market data and  assumptions.  The fair values  determined are reduced by
reserves to adjust for credit risk and liquidity  risk.  Credit risk is the risk
that the  counterparty  to the  contract  will  fail to  perform  or fail to pay
amounts due. Liquidity risk represents the risk that imperfections in the market
will cause the price to be less than or more than what the price should be based
purely on supply and demand.  There are inherent risks related to the underlying
assumptions in models used to fair value open long-term trading  contracts.  AEP
has independent controls to evaluate the reasonableness of our valuation models.
However,  energy  markets,  especially  electricity  markets,  are imperfect and
volatile and  unforeseen  events can and will cause  reasonable  price curves to
differ  from actual  prices  throughout  a  contract's  term and when  contracts
settle.  Therefore,  there could be significant  adverse or favorable effects on
future  results of  operations  and cash flows if market prices at settlement do
not correlate with the AEP-developed price models.
        Volatility in commodities  markets affects the fair values of all of our
open trading  contracts  exposing  CSPCo to market risk. See  "Quantitative  and
Qualitative  Disclosures  about  Market Risk"  section for a  discussion  of the
policies and procedures used to manage exposure to risk from trading activities.


<PAGE>


Results of Operations
        Net income increased $30.7 million or 146% in the second quarter of 2002
and $26.9 million or 46% in the year-to-date period due to an extraordinary loss
recorded  in the prior  period  second  quarter to  recognize  a stranded  asset
resulting from deregulation.
        A decline in  revenues is mainly due to a decrease  in  wholesale  sales
revenues due to lower  wholesale  energy  prices.  In 2002 the wholesale  energy
sector has been under pressure from lower  commodity  prices in contrast to last
year when we had strong performance from the wholesale business due to favorable
market conditions. The following analyzes the changes in operating revenues:
<TABLE>
<CAPTION>
                                                                   Increase (Decrease)
                                            Second Quarter                              Year-to-Date
                                      (in millions)            %                (in millions)                %
                                                               -                                             -
<S>                                        <C>               <C>                     <C>                   <C>
       Electricity Marketing
        And Trading*                       $(197.1)          (20)                    $(365.8)              (18)
       Energy Delivery*                        2.8             2                         6.3                 3
       Sales to AEP Affiliates                (1.7)           (9)                      (12.7)              (34)
                                           -------                                   -------
            Total                          $(196.0)          (18)                    $(372.2)              (17)
                                           =======                                   =======
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.

        The  decrease in electric  marketing  and trading  revenues  was largely
driven  by the  decline  in sales by the AEP Power  Pool due to lower  wholesale
energy prices that decreased margins.
        Operating expenses declined 18% in the second quarter of 2002 and 17% in
the  year-to-date  period of 2002.  The changes in the  components  of operating
expenses were:
<TABLE>
<CAPTION>
                                                               Increase (Decrease)
                                       Second Quarter                                 Year-to-Date
                                  (in millions)           %                 (in millions)                %
                                                          -                                              -
<S>                                    <C>               <C>                     <C>                   <C>
       Fuel                            $   0.7             2                     $  (0.7)               (1)
       Electricity Marketing
        and Trading Purchases           (204.7)          (26)                     (366.4)              (23)
       Purchases from AEP
        Affiliates                        10.1            15                         9.4                 7
       Other Operation                     7.8            14                         7.4                 7
       Maintenance                        (4.7)          (24)                       (9.3)              (24)
       Depreciation and
        Amortization                       1.0             3                         2.3                 4
       Taxes other Than Income
        Taxes                             (2.7)           (9)                       (3.2)               (5)
       Income Taxes                        1.4             7                        (0.5)               (1)
                                       -------                                   -------
            Total                      $(191.1)          (18)                    $(361.0)              (17)
                                       =======                                   =======
</TABLE>

        Electricity  marketing and trading  purchases also declined due to lower
wholesale  energy costs  driven by market  conditions.
        Other  operation expense  increased  in both  periods  primarily  due to
post  retirement benefits expense and property insurance.
        Maintenance expenses decreased in the second quarter and  year-to-date
of 2002 due to boiler  overhaul work that was performed during 2001. Expenses
for maintaining  distribution overhead lines and underground lines were also
lower in both periods of 2002.
<PAGE>
        The increase in income taxes for the second quarter is predominately due
to an  increase  in  pre-tax  income.  The  decrease  in  income  taxes  for the
year-to-date  period is  predominately  due to a  decrease in pre-tax income and
changes in certain book/tax timing  differences  accounted for on a flow-through
basis offset in part by a decrease in deferred state taxes.
        The  decrease  in  nonoperating  income  which  was  offset  by a larger
decrease in non-operating  expenses was due to a reduction in net gains from AEP
Power  Pool  trading  transactions  outside  of  the  AEP  System's  traditional
marketing  area. The AEP Power Pool enters into power trading  transactions  for
the purchase and sale of  electricity  and for options,  futures and swaps.  The
Company's  share  of  the  AEP  Power  Pool's  gains  and  losses  from  forward
electricity trading transactions outside of the AEP System traditional marketing
area and for speculative financial  transactions  (options,  futures,  swaps) is
included in nonoperating  income and expense.  The decrease reflects a reduction
in electricity prices and margins due to a decrease in demand.
                   The decrease in interest was  primarily  due to a decrease in
the  outstanding  balance of long-term debt since the first quarter of 2001, the
refinancing  of debt at favorable  interest  rates and a reduction in short-term
interest rates.

<PAGE>
<TABLE>
<CAPTION>
                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)
                                             Three Months Ended June 30,             Six Months Ended June 30,
                                              2002                  2001              2002                2001
                                              ----                  ----              ----                ----
                                                                    (in thousands)
<S>                                        <C>                 <C>                <C>                <C>
OPERATING REVENUES:
    Electricity Marketing and Trading      $772,779            $  969,836         $1,611,868         $1,977,667
    Energy Delivery                         123,062               120,314            225,610            219,310
    Sales to AEP Affiliates                  17,275                18,945             24,953             37,691
                                           --------            ----------         ----------         ----------
           TOTAL OPERATING REVENUES         913,116             1,109,095          1,862,431          2,234,668
                                           --------            ----------         ----------         ----------

OPERATING EXPENSES:
   Fuel                                      43,064                42,368             88,714             89,398
   Purchased Power:
      Electricity Marketing and Trading     572,644               777,356          1,210,565          1,576,995
      AEP Affiliates                         78,622                68,504            150,204            140,776
   Other Operation                           62,273                54,510            116,431            109,058
   Maintenance                               15,050                19,729             29,190             38,509
   Depreciation and Amortization             32,402                31,379             65,138             62,861
   Taxes Other Than Income Taxes             29,330                32,079             59,606             62,766
   Income Taxes                              21,691                20,276             38,995             39,479
                                           --------            ----------         ----------         ----------
           TOTAL OPERATING EXPENSES         855,076             1,046,201          1,758,843          2,119,842
                                           --------            ----------         ----------         ----------

OPERATING INCOME                             58,040                62,894            103,588            114,826

NONOPERATING INCOME                         275,637               352,505            533,215            605,351

NONOPERATING EXPENSES                       265,114               348,255            519,242            596,047

NONOPERATING INCOME TAX EXPENSE               3,450                 1,238              4,797              2,820

INTEREST CHARGES                             13,392                18,488             27,185             36,221
                                           --------            ----------         ----------         ----------

INCOME BEFORE EXTRAORDINARY ITEM             51,721                47,418             85,579             85,089

EXTRAORDINARY LOSS - EFFECTS OF
 DEREGULATION (INCLUSIVE OF TAX BENEFIT
 OF $8,353,000)                                -                  (26,407)              -               (26,407)
                                           --------            ----------         ----------         ----------

NET INCOME                                   51,721                21,011             85,579             58,682

PREFERRED STOCK DIVIDEND REQUIREMENTS           203                   301                384                603
                                           --------            ----------         ----------         ----------

EARNINGS APPLICABLE TO COMMON STOCK        $ 51,518            $   20,710         $   85,195         $   58,079
                                           ========            ==========         ==========         ==========
</TABLE>
<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)
                                         Three Months Ended June 30,               Six Months Ended June 30,
                                          2002                  2001                 2002              2001
                                          ----                  ----                 ----              ----
                                                                    (in thousands)
<S>                                     <C>                   <C>                  <C>              <C>
NET INCOME                              $51,721               $21,011              $85,579          $58,682

OTHER COMPREHENSIVE INCOME (LOSS)
  Cash Flow Power Hedge                   1,449                  -                   1,449             -
                                        -------               -------              -------          -------
COMPREHENSIVE INCOME                    $53,170               $21,011              $87,028          $58,682
                                        =======               =======              =======          =======
</TABLE>
The common stock of the Company is wholly owned by AEP.

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

                                    Three Months Ended June 30,              Six Months Ended June 30,
                                     2002                2001                2002               2001
                                     ----                ----                ----               ----
                                                                        (in thousands)
<S>                               <C>                  <C>                 <C>               <C>
BALANCE AT BEGINNING OF PERIOD    $187,766             $115,486            $176,103          $ 99,069
NET INCOME                          51,721               21,011              85,579            58,682
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                    21,768               20,738              43,534            41,476
    Preferred Stock                    175                  263                 350               525
  Capital Stock Expense                254                  253                 508               507
                                  --------             --------            --------          --------

BALANCE AT END OF PERIOD          $217,290             $115,243            $217,290          $115,243
                                  ========             ========            ========          ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                           June 30, 2002           December 31, 2001
                                                           -------------           -----------------
                                                                          (in thousands)
<S>                                                             <C>                        <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                                   $1,579,404                 $1,574,506
   Transmission                                                    409,373                    401,405
   Distribution                                                  1,183,240                  1,159,105
   General                                                         149,750                    146,732
   Construction Work in Progress                                    80,695                     72,572
                                                                ----------                 ----------
       Total Electric Utility Plant                              3,402,462                  3,354,320
   Accumulated Depreciation and Amortization                     1,424,191                  1,377,032
                                                                ----------                 ----------
        NET ELECTRIC UTILITY PLANT                               1,978,271                  1,977,288
                                                                ----------                 ----------

OTHER PROPERTY AND INVESTMENTS                                      39,319                     40,369
                                                                ----------                 ----------

LONG-TERM ENERGY TRADING CONTRACTS                                 320,819                    193,915
                                                                ----------                 ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                         3,414                     12,358
   Advances to Affiliates                                           20,709                       -
   Accounts Receivable:
      Customers                                                     53,347                     41,770
      Affiliated Companies                                         154,468                     63,470
      Miscellaneous                                                 17,006                     16,968
      Allowance for Uncollectible Accounts                            (751)                      (745)
   Fuel - at average cost                                           21,864                     20,019
   Materials and Supplies - at average cost                         39,716                     38,984
   Accrued Utility Revenues                                         17,376                      7,087
   Energy Trading Contracts                                        518,838                    347,198
   Prepayments and Other Current Assets                             37,919                     28,733
                                                                ----------                 ----------
        TOTAL CURRENT ASSETS                                       883,906                    575,842
                                                                ----------                 ----------

REGULATORY ASSETS                                                  257,378                    262,267
                                                                ----------                 ----------

DEFERRED CHARGES                                                    34,658                     56,187
                                                                ----------                 ----------

        TOTAL ASSETS                                            $3,514,351                 $3,105,868
                                                                ==========                 ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                         June 30, 2002           December 31, 2001
                                                         -------------           -----------------
                                                                            (in thousands)
<S>                                                              <C>                         <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 24,000,000 Shares
      Outstanding - 16,410,426 Shares                            $   41,026                  $   41,026
   Paid-in Capital                                                  574,877                     574,369
   Accumulated Other Comprehensive Income                             1,449                        -
   Retained Earnings                                                217,290                     176,103
                                                                 ----------                  ----------
        Total Common Shareowner's Equity                            834,642                     791,498
   Cumulative Preferred Stock - Subject to
    Mandatory Redemption                                               -                         10,000
   Long-term Debt                                                   445,691                     571,348
                                                                 ----------                  ----------

           TOTAL CAPITALIZATION                                   1,280,333                   1,372,846
                                                                 ----------                  ----------

OTHER NONCURRENT LIABILITIES                                         37,350                      36,715
                                                                 ----------                  ----------

CURRENT LIABILITIES:
   Preferred Stock Due Within One Year                               10,000                        -
   Long-term Debt Due Within One Year                               346,343                     220,500
   Short-term Debt Affiliated                                       250,000                        -
   Advances from Affiliates                                            -                        181,384
   Accounts Payable - General                                        64,131                      62,393
   Accounts Payable - Affiliated Companies                          130,130                      83,697
   Taxes Accrued                                                     83,181                     116,364
   Interest Accrued                                                  10,996                      10,907
   Energy Trading Contracts                                         495,172                     334,958
   Other                                                             32,889                      34,600
                                                                 ----------                  ----------

           TOTAL CURRENT LIABILITIES                              1,422,842                   1,044,803
                                                                 ----------                  ----------

DEFERRED INCOME TAXES                                               439,988                     443,722
                                                                 ----------                  ----------

DEFERRED INVESTMENT TAX CREDITS                                      35,619                      37,176
                                                                 ----------                  ----------

LONG-TERM ENERGY TRADING CONTRACTS                                  282,341                     157,706
                                                                 ----------                  ----------

DEFERRED CREDITS                                                     15,878                      12,900
                                                                 ----------                  ----------

CONTINGENCIES (Note 8)

           TOTAL CAPITALIZATION AND LIABILITIES                  $3,514,351                  $3,105,868
                                                                 ==========                  ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                 Six Months Ended June 30,
                                                                      (in thousands)
                                                                  2002                    2001
                                                                  ----                    ----
<S>                                                           <C>                     <C>
OPERATING ACTIVITIES:
   Net Income                                                 $  85,579               $  58,682
   Adjustments for Noncash Items:
      Depreciation and Amortization                              65,192                  63,686
      Deferred Federal Income Taxes                              (5,432)                 18,384
      Deferred Investment Tax Credits                            (1,557)                 (1,671)
      Deferred Property Tax                                      23,971                  35,416
      Mark-to-Market Energy Trading Contracts                   (11,260)                (52,316)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                (102,607)                (37,869)
      Fuel, Materials and Supplies                               (2,577)                 (6,758)
      Accrued Utility Revenues                                  (10,289)                  9,638
      Prepayments and Other Current Assets                       (9,186)                 19,077
      Accounts Payable                                           48,171                  28,155
      Taxes Accrued                                             (33,183)                (45,627)
   Other Assets                                                  (7,865)                 10,516
   Other Liabilities                                              3,529                 (19,204)
                                                              ---------                --------
           Net Cash Flows From Operating Activities              42,486                  80,109
                                                              ---------                --------

INVESTING ACTIVITIES:
      Construction Expenditures                                 (55,842)                (67,532)
      Proceeds from Sale of Property                                389                   1,284
                                                              ---------                --------
           Net Cash Flows Used For Investing Activities         (55,453)                (66,248)
                                                              ---------                --------

FINANCING ACTIVITIES:
      Change in Advances from Affiliates (net)                 (202,093)                 26,570
      Change in Short-term Debt Affiliated (net)                250,000                    -
      Dividends Paid on Common Stock                            (43,534)                (41,476)
      Dividends Paid on Cumulative Preferred Stock                 (350)                   (525)
                                                              ---------                --------
           Net Cash Flows From (Used For) Financing Activities    4,023                 (15,431)
                                                              ---------                --------

Net Increase (Decrease) in Cash and Cash Equivalents             (8,944)                 (1,570)
Cash and Cash Equivalents at Beginning of Period                 12,358                  11,600
                                                              ---------                --------
Cash and Cash Equivalents at End of Period                    $   3,414                $ 10,030
                                                              =========                ========
</TABLE>
Supplemental Disclosure:
Cash  paid  for  interest  net  of  capitalized   amounts  was  $26,262,000  and
$32,812,000  and for income taxes was  $32,254,000  and  $17,579,000 in 2002 and
2001,  respectively.  Noncash acquisitions under capital leases were $734,000 in
2001.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

       I&M is a  public  utility  engaged  in the  generation,  purchase,  sale,
transmission  and  distribution of electric power to 567,000 retail customers in
its  service  territory  in  northern  and  eastern  Indiana  and a  portion  of
southwestern  Michigan.  As a member  of the AEP  Power  Pool,  I&M  shares  the
revenues and the costs of the AEP Power Pool's  wholesale  sales to  neighboring
utilities and power  marketers  including power trading  transactions.  I&M also
sells wholesale power to municipalities and electric cooperatives.
       The cost of the AEP System's  generating  capacity is allocated among the
AEP Power Pool  members  based on their  relative  peak  demands and  generating
reserves  through the  payment of  capacity  charges and the receipt of capacity
credits. AEP Power Pool members are also compensated for the out-of-pocket costs
of energy  delivered to the AEP Power Pool and charged for energy  received from
the AEP Power Pool. The AEP Power Pool  calculates  each company's  prior twelve
month peak demand relative to the total peak demand of all member companies as a
basis for sharing  revenues and costs.  The result of this  calculation  is each
company's  member load ratio (MLR) which  determines  each company's  percentage
share of revenues and costs.
       I&M is committed  under unit power  agreements to purchase all of AEGCo's
50% share of the 2,600 MW  Rockport  Plant  capacity  unless it is sold to other
utilities.  AEGCo is an affiliate that is not a member of the AEP Power Pool. An
agreement  between  AEGCo and KPCo  provides  for the sale of 390 MW of  AEGCo's
Rockport Plant capacity to KPCo through 2004. Therefore, I&M purchases 910 MW of
AEGCo's 50% share of Rockport Plant capacity.

Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a cost-based  rate-regulated  electric public utility
company,   I&M's  consolidated  financial  statements  reflect  the  actions  of
regulators  that can result in the  recognition  of  revenues  and  expenses  in
different  time  periods  than  enterprises  that  are not  rate  regulated.  In
accordance with SFAS 71,  regulatory  assets (deferred  expenses) and regulatory
liabilities  (future revenue  reductions or refunds) are recorded to reflect the
economic effects of regulation by matching  expenses with their recovery through
regulated revenues in the same accounting period.
        When regulatory assets are probable of recovery through regulated rates,
we record  them as assets  on the  balance  sheet.  We test for  probability  of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation.  If we determine that recovery of a regulatory asset
is no longer  probable,  we write off that regulatory  asset as a charge against
net income.  A write off of regulatory  assets may also reduce future cash flows
since there may be no recovery through regulated rates.


<PAGE>


Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general expenses are recorded when incurred.

Energy Marketing and Trading  Activities - AEP engages in wholesale  electricity
marketing  and  trading  transactions  (trading  activities).  A portion  of the
revenues and costs of AEP's trading  activities are allocated to I&M as a member
of the AEP Power  Pool.  Trading  activities  involve the  purchase  and sale of
energy under  physical  forward  contracts at fixed and variable  prices and the
buying and selling of financial  energy  contracts which include exchange traded
futures and  options and  over-the-counter  options and swaps.  The  majority of
trading  activities  represent physical forward  electricity  contracts that are
typically  settled by entering  into  offsetting  physical  contracts.  Although
trading  contracts are generally  short-term,  there are also long-term  trading
contracts.
           Accounting  standards  applicable to trading  activities require that
changes in the fair value of trading  contracts be recognized in revenues  prior
to settlement and is commonly  referred to as  mark-to-market  (MTM) accounting.
Since I&M is a cost-based  rate-regulated  entity,  changes in the fair value of
physical forward sale and purchase contracts in AEP's traditional marketing area
are deferred as regulatory  liabilities  (gains) or regulatory  assets (losses).
The deferral  reflects the fact that power sales and  purchases  are included in
regulated rates on a settlement basis. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory.  The change in the fair
value of physical forward sale and purchase  contracts outside AEP's traditional
marketing area is included in nonoperating income on a net basis.
         Mark-to-market  accounting represents the change in the unrealized gain
or loss throughout the contract's term. When the contract actually settles, that
is, the energy is actually  delivered in a sale or received in a purchase or the
parties agree to forego  delivery and receipt of  electricity  and net settle in
cash, the unrealized  gain or loss is reversed and the actual realized cash gain
or loss is  recognized in the income  statement.  Therefore,  as the  contract's
market value  changes over the  contract's  term an  unrealized  gain or loss is
deferred for contracts with delivery points in AEP's traditional  marketing area
and for contracts with delivery  points outside of AEP's  traditional  marketing
area the unrealized gain or loss is recognized as nonoperating  income. When the
contract  settles  the total gain or loss is  realized in cash and the impact on
the income  statement  depends on whether  the  contract's  delivery  points are
within or  outside of AEP's  traditional  marketing  area.  For  contracts  with
delivery  points in AEP's  traditional  marketing  area,  the total gain or loss
realized in cash is recognized in the income statement. Physical forward trading
sale  contracts  with delivery  points in AEP's  traditional  marketing area are
included  in  revenues  when the  contracts  settle.  Physical  forward  trading
purchase contracts with delivery points in AEP's traditional  marketing area are
included in  purchased  power  expense when they  settle.  Prior to  settlement,
changes in the fair value of physical  forward  sale and  purchase  contracts in
AEP's traditional marketing area are deferred as regulatory  liabilities (gains)
or regulatory  assets  (losses).  For contacts with delivery  points  outside of
AEP's  traditional  marketing area only the difference  between the  accumulated

<PAGE>

unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized  in the  income  statement.  Physical  forward  sales  contracts  for
delivery   outside  of  AEP's   traditional   marketing  area  are  included  in
nonoperating  income  when  the  contract  settles.  Physical  forward  purchase
contracts for delivery outside of AEP's traditional  marketing area are included
in nonoperating expenses when the contract settles. Prior to settlement, changes
in the fair value of physical forward sale and purchase  contracts with delivery
points outside of AEP's traditional  marketing area are included in nonoperating
income on a net basis.  Unrealized  mark-to-market gains and losses are included
in the  Balance  Sheet as  energy  trading  contract  assets or  liabilities  as
appropriate.
        Trading of electricity options,  futures and swaps, represents financial
transactions  with  unrealized  gains and losses  from  changes  in fair  values
reported net in  nonoperating  income  until the  contracts  settle.  When these
financial  contracts  settle,  we  record  our  share  of the  net  proceeds  in
nonoperating  income and  reverse to  nonoperating  income the prior  cumulative
unrealized net gain or loss.
        The  fair  value  of open  short-term  trading  contracts  are  based on
exchange  prices and broker quotes.  We  mark-to-market  open long-term  trading
contracts based mainly on AEP-developed  valuation models. These models estimate
future energy  prices based on existing  market and broker quotes and supply and
demand market data and  assumptions.  The fair values  determined are reduced by
reserves to adjust for credit risk and liquidity  risk.  Credit risk is the risk
that the  counterparty  to the  contract  will  fail to  perform  or fail to pay
amounts due. Liquidity risk represents the risk that imperfections in the market
will  cause the  price to be less or more  than  what the price  should be based
purely on supply and demand.  There are inherent risks related to the underlying
assumptions in models used to fair value open long-term trading  contracts.  AEP
has independent controls to evaluate the reasonableness of our valuation models.
However,  energy  markets,  especially  electricity  markets,  are imperfect and
volatile and  unforeseen  events can and will cause  reasonable  price curves to
differ  from actual  prices  throughout  a  contract's  term and when  contracts
settle.  Therefore,  there could be significant  adverse or favorable effects on
future  results of  operations  and cash flows if market prices at settlement do
not correlate with the AEP-developed price models.
        Volatility in commodities  markets affects the fair values of all of our
open  trading  contracts  exposing  I&M to market risk.  See  "Quantitative  and
Qualitative  Disclosures  about  Market Risk"  section for a  discussion  of the
policies and procedures used to manage exposure to risk from trading activities.

Results of Operations
          Net income  decreased  $19.9 million or 73% in the second  quarter and
$41.2 million or 69% in the year-to-date  period due primarily to a reduction in
generation as a result of a refueling  outage at both units of I&M's Cook Plant,
reduced  generation  at  Rockport  Plant due to  maintenance  outages  and lower
margins on electricity sales.
<PAGE>
        Operating  revenues  decreased 22% in the second quarter and 21% for the
year-to-date  period due to decreased wholesale marketing and trading prices and
the decline in generation due to power plant outages. The following analyzes the
changes in operating revenues:
<TABLE>
<CAPTION>
                                                                   Increase (Decrease)
                                             Second Quarter                              Year-to-Date
                                      (in millions)            %                (in millions)                %
                                                               -                                             -
<S>                                        <C>               <C>                     <C>                   <C>
       Electricity Marketing
        and Trading*                       $(255.5)          (23)                    $(481.1)              (21)
       Energy Delivery*                       (0.3)          N.M.                       (3.7)               (2)
       Sales to AEP Affiliates               (19.0)          (30)                      (42.8)              (32)
                                           -------                                   -------
            Total                          $(274.8)          (22)                    $(527.6)              (21)
                                           =======                                   =======
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.
       N.M. = Not Meaningful

        The decrease in electricity  marketing and trading revenues was due to a
decline in sales by the AEP Power  Pool due to lower  wholesale  energy  prices.
Revenues from sales to AEP affiliates  declined  significantly  reflecting  less
power  being  available  for  sale as one  unit of the Cook  Nuclear  Plant  was
shutdown for  refueling in each of the first two quarters of 2002 and both units
of Rockport Plant underwent  scheduled  planned boiler  maintenance in the first
quarter of 2002. AEP Power Pool members are  compensated  for the  out-of-pocket
costs of energy  delivered to the AEP Power Pool and charged for energy received
from the AEP Power Pool. With the outages in 2002,  I&M's  available  generation
declined resulting in less power being delivered to the AEP Power Pool.
        Operating expenses declined in 2002.  The changes in the components of
operating expenses were:
<TABLE>
<CAPTION>
                                                                 Increase (Decrease)
                                                                 -------------------
                                            Second Quarter                              Year-to-Date
                                    (in millions)            %                (in millions)                %
                                                             -                                             -

<S>                                      <C>               <C>                     <C>                   <C>
       Fuel                              $  (7.3)          (12)                    $ (17.1)              (14)
       Electricity Marketing
        and Trading Purchases             (260.1)          (30)                     (476.3)              (27)
       Purchases from AEP
        Affiliates                           7.3            13                        (2.7)               (2)
       Other Operation                      11.0            10                        25.4                12
       Maintenance                           8.0            26                        10.9                18
       Depreciation and
        Amortization                         1.0             3                         2.2                 3
       Taxes other Than Income
        Taxes                                0.5             3                         0.5                 1
       Income Taxes                         (7.8)          (50)                      (20.6)              (60)
                                         -------                                   -------
            Total                        $(247.4)          (20)                    $(477.8)              (19)
                                         =======                                   =======
</TABLE>
        Fuel  expense  decreased  primarily  due to the  decline  in  generation
reflecting the plant outages as both units of our nuclear plant were refueled in
2002.
        The decrease in  electricity  marketing and trading  purchases  resulted
mainly from the decrease in energy prices.
        Purchases from AEP affiliates increased in the second  quarter due to
the timing of the Rockport Plant outages in first quarter  of 2002 and in second
quarter of 2001.  I&M is  required  to  purchase AEGCo's Rockport Plant
generation under their unit power agreement.
        Other operation and maintenance  expenses increased due to costs related
to the  nuclear  plant  refueling  outages.

<PAGE>
        The  decrease in income tax expense  attributable  to  operations is due
primarily to a decline in pre-tax operating income.
        Nonoperating income and nonoperating expenses decreased  due to lower
prices for power sold and  purchased  outside of AEP's traditional marketing
area reflecting reduced demand.
         The decrease in nonoperating  income tax expense  reflects a decline in
pre-tax nonoperating income.
<PAGE>
<TABLE>
<CAPTION>
                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                  Three Months Ended June 30,        Six Months Ended June 30,
                                                2002                  2001              2002                2001
                                                ----                  ----              ----                ----
                                                                      (in thousands)
<S>                                           <C>                 <C>               <C>                <C>
OPERATING REVENUES:
    Electricity Marketing and Trading         $860,979            $1,116,459        $1,777,992         $2,259,076
    Energy Delivery                             78,657                78,970           153,194            156,907
    Sales to AEP Affiliates                     45,401                64,445            92,610            135,429
                                              --------            ----------        ----------         ----------

           TOTAL OPERATING REVENUES            985,037             1,259,874         2,023,796          2,551,412
                                              --------            ----------        ----------         ----------

OPERATING EXPENSES:
   Fuel                                         53,163                60,491           107,319            124,464
   Purchased Power:
      Electricity Marketing and Trading        620,545               880,649         1,312,351          1,788,688
      AEP Affiliates                            63,110                55,805           116,617            119,353
   Other Operation                             121,180               110,197           232,946            207,560
   Maintenance                                  39,580                31,506            70,623             59,681
   Depreciation and Amortization                41,870                40,840            83,736             81,563
   Taxes Other Than Income Taxes                17,855                17,336            36,096             35,574
   Income Taxes                                  7,869                15,710            13,880             34,491
                                              --------            ----------        ----------         ----------

           TOTAL OPERATING EXPENSES            965,172             1,212,534         1,973,568          2,451,374
                                              --------            ----------        ----------         ----------

OPERATING INCOME                                19,865                47,340            50,228            100,038

NONOPERATING INCOME                            315,454               415,752           610,639            718,026

NONOPERATING EXPENSES                          303,005               409,323           594,496            705,037

NONOPERATING INCOME TAX EXPENSE                  1,313                 2,018               888              4,133

INTEREST CHARGES                                23,507                24,377            46,931             49,157
                                              --------            ----------        ----------         ----------

NET INCOME                                       7,494                27,374            18,552             59,737

PREFERRED STOCK DIVIDEND REQUIREMENTS            1,153                 1,156             2,308              2,311
                                              --------            ----------        ----------         ----------

EARNINGS APPLICABLE TO COMMON STOCK           $  6,341            $   26,218        $   16,244         $   57,426
                                              ========            ==========        ==========         ==========
</TABLE>
<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                            Three Months Ended June 30,        Six Months Ended June 30,
                                          2002                  2001              2002                2001
                                          ----                  ----              ----                ----
                                                                (in thousands)
<S>                                      <C>                   <C>               <C>                <C>
NET INCOME                               $ 7,494               $27,374           $18,552            $59,737

OTHER COMPREHENSIVE INCOME (LOSS)
    Cash Flow Interest Rate Hedge          1,228                  (903)            2,487             (2,822)
    Power Trading Hedge                    1,567                  -                1,567               -
                                         -------               -------           -------            -------

COMPREHENSIVE INCOME                     $10,289               $26,471           $22,606            $56,915
                                         =======               =======           =======            =======
</TABLE>
The  common  stock  of I&M is  wholly  owned  by AEP.  See  Notes  to  Financial
Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                             Three Months Ended June 30,               Six Months Ended June 30,
                                                2002                2001                  2002              2001
                                                ----                ----                  ----              ----
                                                                   (in thousands)
<S>                                           <C>                 <C>                   <C>              <C>
BALANCE AT BEGINNING OF PERIOD                $84,508             $34,651               $74,605          $ 3,443

NET INCOME                                      7,494              27,374                18,552           59,737

DEDUCTIONS:
Cash Dividends Declared -
   Cumulative Preferred Stock                   1,121               1,122                 2,243            2,244
Capital Stock Expense                              34                  34                    67               67
                                              -------             -------               -------          -------

BALANCE AT END OF PERIOD                      $90,847             $60,869               $90,847          $60,869
                                              =======             =======               =======          =======
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                         June 30, 2002           December 31, 2001
                                                         -------------           -----------------
                                                                      (in thousands)
<S>                                                          <C>                        <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                                $2,765,097                 $2,758,160
   Transmission                                                 958,863                    957,336
   Distribution                                                 907,104                    900,921
   General (including nuclear fuel)                             238,213                    233,005
   Construction Work in Progress                                114,117                     74,299
                                                             ----------                 ----------
        Total Electric Utility Plant                          4,983,394                  4,923,721
   Accumulated Depreciation and Amortization                  2,505,922                  2,436,972
                                                             ----------                 ----------
             NET ELECTRIC UTILITY PLANT                       2,477,472                  2,486,749
                                                             ----------                 ----------

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
  DISPOSAL TRUST FUNDS                                          851,070                    834,109
                                                             ----------                 ----------

LONG-TERM ENERGY TRADING CONTRACTS                              356,052                    215,544
                                                             ----------                 ----------

OTHER PROPERTY AND INVESTMENTS                                  121,961                    127,977
                                                             ----------                 ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                     13,708                     16,804
   Advances to Affiliates                                          -                        46,309
   Accounts Receivable:
      Customers                                                  76,763                     60,864
      Affiliated Companies                                      189,093                     31,908
      Miscellaneous                                              41,366                     25,398
      Allowance for Uncollectible Accounts                         (715)                      (741)
   Fuel - at average cost                                        29,340                     28,989
   Materials and Supplies - at average cost                      90,900                     91,440
   Energy Trading Contracts                                     587,571                    399,195
   Accrued Utility Revenues                                       2,920                      2,072
   Prepayments                                                   11,027                      6,497
                                                             ----------                 ----------
          TOTAL CURRENT ASSETS                                1,041,973                    708,735
                                                             ----------                 ----------

REGULATORY ASSETS                                               412,308                    408,927
                                                             ----------                 ----------

DEFERRED CHARGES                                                 36,183                     34,967
                                                             ----------                 ----------

          TOTAL ASSETS                                       $5,297,019                 $4,817,008
                                                             ==========                 ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                        June 30, 2002           December 31, 2001
                                                        -------------           -----------------
                                                                       (in thousands)
<S>                                                         <C>                         <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 2,500,000 Shares
      Outstanding - 1,400,000 Shares                        $   56,584                  $   56,584
   Paid-in Capital                                             733,491                     733,216
   Accumulated Other Comprehensive Income (Loss)                   219                      (3,835)
   Retained Earnings                                            90,847                      74,605
                                                            ----------                  ----------
        Total Common Shareowner's Equity                       881,141                     860,570
   Cumulative Preferred Stock:
      Not Subject to Mandatory Redemption                        8,103                       8,736
      Subject to Mandatory Redemption                           64,945                      64,945
   Long-term Debt                                            1,364,500                   1,312,082
                                                            ----------                  ----------

           TOTAL CAPITALIZATION                              2,318,689                   2,246,333
                                                            ----------                  ----------

OTHER NONCURRENT LIABILITIES:
   Nuclear Decommissioning                                     610,986                     600,244
   Other                                                        85,716                      87,025
                                                            ----------                  ----------

           TOTAL OTHER NONCURRENT LIABILITIES                  696,702                     687,269
                                                            ----------                  ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                          290,000                     340,000
   Advances from Affiliates                                     11,806                        -
   Accounts Payable:
      General                                                  118,187                      90,817
      Affiliated Companies                                     150,769                      43,956
   Taxes Accrued                                                68,048                      69,761
   Interest Accrued                                             23,398                      20,691
   Obligations Under Capital Leases                              9,025                      10,840
   Energy Trading Contracts                                    564,572                     383,714
   Other                                                        79,169                      72,435
                                                            ----------                  ----------

           TOTAL CURRENT LIABILITIES                         1,314,974                   1,032,214
                                                            ----------                  ----------

DEFERRED INCOME TAXES                                          384,370                     400,531
                                                            ----------                  ----------

DEFERRED INVESTMENT TAX CREDITS                                101,760                     105,449
                                                            ----------                  ----------

DEFERRED GAIN ON SALE AND LEASEBACK
 - ROCKPORT PLANT UNIT 2                                        75,739                      77,592
                                                            ----------                  ----------

LONG-TERM ENERGY TRADING CONTRACTS                             318,158                     175,581
                                                            ----------                  ----------

DEFERRED CREDITS                                                86,627                      92,039
                                                            ----------                  ----------

CONTINGENCIES (Note 8)

                TOTAL CAPITALIZATION AND LIABILITIES        $5,297,019                  $4,817,008
                                                            ==========                  ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                       Six Months Ended June 30,
                                                                2002                  2001
                                                                ----                  ----
                                                                      (in thousands)
<S>                                                            <C>                      <C>
OPERATING ACTIVITIES:
   Net Income                                                  $  18,552                $  59,737
   Adjustments for Noncash Items:
      Depreciation and Amortization                               83,779                   83,090
      Deferral of Incremental Nuclear
       Refueling Outage Expenses (net)                           (45,701)                    (771)
      Unrecovered Fuel and Purchased Power Costs                  18,751                   18,751
      Amortization of Nuclear Outage Costs                        20,000                   20,000
      Deferred Federal Income Taxes                               (7,723)                  (4,256)
      Deferred Investment Tax Credits                             (3,689)                  (3,736)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                 (189,078)                  10,372
      Fuel, Materials and Supplies                                   189                  (13,858)
      Accrued Utility Revenues                                      (848)                    -
      Accounts Payable                                           134,183                  (41,383)
      Taxes Accrued                                               (1,713)                  31,255
   Mark-to-Market Energy Trading Contracts                         2,377                  (84,756)
   Regulatory Liability - Trading Gains                              838                   34,080
   Regulatory Assets - Trading Losses                             (8,166)                   4,079
   Change in Other Assets                                        (24,349)                  18,409
   Change in Other Liabilities                                    11,802                   (1,448)
                                                               ---------                ---------
           Net Cash Flows From Operating Activities                9,204                  129,565
                                                               ---------                ---------

INVESTING ACTIVITIES:
      Construction Expenditures                                  (67,396)                 (41,321)
      Buyout of Nuclear Fuel Leases                                 -                     (92,616)
      Other                                                         -                         324
                                                               ---------                ---------
           Net Cash Flows Used For Investing Activities          (67,396)                (133,613)
                                                               ---------                ---------

FINANCING ACTIVITIES:
      Issuance of Long-term Debt                                  49,648                     -
      Retirement of Cumulative Preferred Stock                      (424)                    -
      Retirement of Long-term Debt                               (50,000)                 (44,922)
      Change in Advances from Affiliates (net)                    58,115                   48,448
      Dividends Paid on Cumulative Preferred Stock                (2,243)                  (2,244)
                                                               ---------                ---------
           Net Cash Flows From Financing Activities               55,096                    1,282
                                                               ---------                ---------

Net Decrease in Cash and Cash Equivalents                         (3,096)                  (2,766)
Cash and Cash Equivalents at Beginning of Period                  16,804                   14,835
                                                               ---------                ---------
Cash and Cash Equivalents at End of Period                     $  13,708                $  12,069
                                                               =========                =========
</TABLE>
Supplemental Disclosure:
Cash  paid  for  interest  net  of  capitalized   amounts  was  $42,695,000  and
$46,243,000  and for income taxes was  $18,711,000  and  $11,073,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $1,020,000 in
2001.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
                             KENTUCKY POWER COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

       KPCo is a public  utility  engaged  in the  generation,  purchase,  sale,
transmission and distribution of electric power serving 172,000 retail customers
in  eastern  Kentucky.  KPCo as a member  of the AEP  Power  Pool  shares in the
revenues  and  costs of the AEP  Power  Pool's  wholesale  sales to  neighboring
utility systems and power marketers including power trading  transactions.  KPCo
also sells wholesale power to municipalities.
       The cost of the AEP Power Pool's  generating  capacity is allocated among
the Pool members based on their  relative peak demands and  generating  reserves
through the payment of capacity charges and the receipt of capacity credits. AEP
Power Pool members are also compensated for their  out-of-pocket costs of energy
delivered  to the AEP Power Pool and  charged for energy  received  from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member  companies as a basis for
sharing  revenues and costs.  The result of this  calculation is the member load
ratio (MLR) which  determines each company's  percentage share of AEP Power Pool
revenues and costs.

Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a cost-based  rate-regulated  electric public utility
company,  KPCo's financial statements reflect the actions of regulators that can
result in the  recognition  of revenues and  expenses in different  time periods
than  enterprises  that are not rate  regulated.  In  accordance  with  SFAS 71,
regulatory assets (deferred expenses) and regulatory liabilities (future revenue
reductions  or  refunds)  are  recorded  to  reflect  the  economic  effects  of
regulation by matching expenses with their recovery through  regulated  revenues
in the same accounting period.
        When regulatory assets are probable of recovery through regulated rates,
we record  them as assets  on the  balance  sheet.  We test for  probability  of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation.  If we determine that recovery of a regulatory asset
is no longer  probable,  we write off that regulatory  asset as a charge against
net income.  A write off of regulatory  assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general, expenses are recorded when incurred.

Energy Marketing and Trading  Activities - AEP engages in wholesale  electricity
marketing  and  trading  transactions  (trading  activities).  A portion  of the
revenues and costs of AEP's trading activities are allocated to KPCo as a member
of the AEP Power  Pool.  Trading  activities  involve the  purchase  and sale of
energy under  physical  forward  contracts at fixed and variable  prices and the

<PAGE>

buying and selling of financial  energy  contracts which include exchange traded
futures and  options and  over-the-counter  options and swaps.  The  majority of
trading  activities  represent physical forward  electricity  contracts that are
typically  settled by entering  into  offsetting  physical  contracts.  Although
trading  contracts are generally  short-term,  there are also long-term  trading
contracts.
           Accounting  standards  applicable to trading  activities require that
changes in the fair value of trading contacts be recognized in revenues prior to
settlement and is commonly referred to as mark-to-market (MTM) accounting. Since
KPCo is a  cost-based  rate-regulated  entity,  changes  in the  fair  value  of
physical forward sale and purchase contracts in AEP's traditional marketing area
are deferred as regulatory  liabilities  (gains) or regulatory  assets (losses).
AEP's traditional  marketing area is up to two transmission systems from the AEP
service  territory.  The change in the fair value of physical  forward  sale and
purchase  contracts  outside  AEP's  traditional  marketing  area is included in
nonoperating income on a net basis.
         Mark-to-market  accounting represents the change in the unrealized gain
or loss throughout the contract's term. When the contract actually settles, that
is, the energy is actually  delivered in a sale or received in a purchase or the
parties agree to forego  delivery and receipt of  electricity  and net settle in
cash, the unrealized  gain or loss is reversed and the actual realized cash gain
or loss is  recognized in the income  statement.  Therefore,  as the  contract's
market value  changes over the  contract's  term an  unrealized  gain or loss is
deferred for contracts with delivery points in AEP's traditional  marketing area
and for contracts with delivery  points outside of AEP's  traditional  marketing
area the unrealized gain or loss is recognized as nonoperating  income. When the
contract  settles  the total gain or loss is  realized in cash and the impact on
the income  statement  depends on whether  the  contract's  delivery  points are
within or  outside of AEP's  traditional  marketing  area.  For  contracts  with
delivery  points in AEP's  traditional  marketing  area,  the total gain or loss
realized in cash is recognized in the income statement. Physical forward trading
sale  contracts  with delivery  points in AEP's  traditional  marketing area are
included  in  revenues  when the  contracts  settle.  Physical  forward  trading
purchase contracts with delivery points in AEP's traditional  marketing area are
included in  purchased  power  expense when they  settle.  Prior to  settlement,
changes in the fair value of physical  forward  sale and  purchase  contracts in
AEP's traditional marketing area are deferred as regulatory  liabilities (gains)
or regulatory  assets  (losses).  For contacts with delivery  points  outside of
AEP's  traditional  marketing area only the difference  between the  accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized  in the  income  statement.  Physical  forward  sales  contracts  for
delivery   outside  of  AEP's   traditional   marketing  area  are  included  in
nonoperating  income  when  the  contract  settles.  Physical  forward  purchase
contracts for delivery outside of AEP's traditional  marketing area are included
in nonoperating expenses when the contract settles. Prior to settlement, changes
in the fair value of physical forward sale and purchase  contracts with delivery
points outside of AEP's traditional  marketing area are included in nonoperating
income on a net basis.  Unrealized  mark-to-market gains and losses are included
in the balance sheet as energy trading assets or liabilities.


<PAGE>


        Trading of electricity options,  futures and swaps, represents financial
transactions  with  unrealized  gains and losses  from  changes  in fair  values
reported net in  nonoperating  income  until the  contracts  settle.  When these
financial  contracts  settle,  we  record  our  share  of the  net  proceeds  in
nonoperating  income and reverse to  nonoperating  income the  cumulative  prior
unrealized net gain or loss.
        The  fair  value  of open  short-term  trading  contracts  are  based on
exchange  prices and broker quotes.  We  mark-to-market  open long-term  trading
contracts based mainly on AEP-developed  valuation models. These models estimate
future energy  prices based on existing  market and broker quotes and supply and
demand market data and  assumptions.  The fair values  determined are reduced by
reserves to adjust for credit risk and liquidity  risk.  Credit risk is the risk
that the  counterparty  to the  contract  will  fail to  perform  or fail to pay
amounts due. Liquidity risk represents the risk that imperfections in the market
will cause the price to be less than or more than what the price should be based
purely on supply and demand.  There are inherent risks related to the underlying
assumptions in models used to fair value open long-term trading  contracts.  AEP
has independent controls to evaluate the reasonableness of our valuation models.
However,  energy  markets,  especially  electricity  markets,  are imperfect and
volatile and  unforeseen  events can and will cause  reasonable  price curves to
differ  from actual  prices  throughout  a  contract's  term and when  contracts
settle.  Therefore,  there could be significant  adverse or favorable effects on
future  results of  operations  and cash flows if market prices at settlement do
not correlate with the AEP-developed price models.
        Volatility in commodities  markets affects the fair values of all of our
open trading  contracts  exposing KPCo to market risk. See the "Quantitative and
Qualitative  Disclosures  About  Market  Risk"  section  of Part I, Item 2 for a
discussion of the policies and procedures  used to manage  exposure to risk from
trading activities.

Results of Operations
        Revenues decreased for both the quarter and year-to-date by 28% and 26%,
respectively.  These declines were offset by  improvements in both operating and
nonoperating margins resulting in increases in net income of 91% and 58% or $2.5
million for the quarter and $5.7 million year-to-date.
        The following analyzes the changes in operating revenues:
<TABLE>
<CAPTION>
                                                             Increase (Decrease)
                                            Second Quarter                              Year-to-Date
                                     (in millions)           %              (in millions)                  %
                                                             -                                             -
<S>                                        <C>             <C>                     <C>                   <C>
       Electricity Marketing
        and Trading*                       $(120)          (30)                    $(222)                (27)
       Energy Delivery*                        1             2                        (1)                 (1)
       Sales to AEP Affiliates                (3)          (26)                       (7)                (31)
                                           -----                                   -----
            Total                          $(122)          (28)                    $(230)                (26)
                                           =====                                   =====
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.

        The decrease in revenues is due  primarily to a decrease in  electricity
trading  prices in both the  first and  second  quarter.  In 2002 the  wholesale
energy sector has been under pressure from lower commodity prices in contrast to
last year when we had strong  performance  from the  wholesale  business  due to
favorable market conditions.
<PAGE>
<TABLE>
<CAPTION>
        Significant changes in the components of operating expenses were:
                                                                 Increase (Decrease)
                                                  Second Quarter                        Year-to-Date
                                           (in millions)           %          (in millions)              %
                                                                   -                                     -
<S>                                              <C>            <C>                 <C>                <C>
       Fuel                                      $  -             -                 $    4              11
       Electricity Marketing
        and Trading Purchases                     (125)          (36)                 (231)            (33)
       Purchases from AEP Affiliates                -             -                     (7)            (10)
       Other Operation                              (2)          (11)                   (4)            (13)
       Maintenance                                   3            56                     2              19
       Taxes Other Than Income Taxes                 1            25                     1              14
       Income Taxes                                 (1)          (25)                    1              12
</TABLE>

        Year-to-date  fuel expense  increased as a result of fewer  credits from
profits on trading power and  increases in the cost of coal.  Under the Kentucky
commission's  fuel  clause  mechanism,  a portion of the  profits  on  wholesale
transactions are shared with the customers.  This sharing is recognized  through
credits to fuel  expense.  As margins on  wholesale  electricity  marketing  and
trading  transactions  declined,  the amount of credits  shared through the fuel
clause adjustment mechanism decreased.
        The  decreases in purchased  power  expense were  attributable  to lower
prices  resulting  from general  market trends and reduced volume of electricity
traded stemming from continued soft demand in the wholesale power market.
        Other operation expense decreased due to reduced consumption of emission
allowances, increased AEP transmission equalization credits and reduced accruals
for  trading  incentive  compensation.  Under the AEP East  Region  Transmission
Agreement,  KPCo and  certain  affiliates  share the costs  associated  with the
ownership of their transmission  system based upon each company' peak demand and
investment.  A decrease in KPCo's peak demand relative to its  affiliates'  peak
demand  was the  main  reason  for the  increase  in  transmission  equalization
credits.
        Maintenance  expense  increased  as a  result  of  planned  power  plant
outages.
        Taxes other than income taxes  increased with increases in payroll taxes
and real and personal property taxes.  Income taxes  year-to-date have increased
primarily as a result of increases in pre-tax income.
        Decreases in  nonoperating  income and expenses were due to decreases in
power trading revenues and purchases from  non-regulated  AEP Power Pool trading
transactions  outside of the AEP System's  traditional  marketing  area. As with
power trading  activity within the traditional  marketing  areas,  non-regulated
trading transactions also experienced declining prices due to reduced demand.
<PAGE>
<TABLE>
<CAPTION>
                             KENTUCKY POWER COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                      Three Months Ended June 30,        Six Months Ended June 30,
                                                    2002                  2001              2002                2001
                                                    ----                  ----              ----                ----
                                                                          (in thousands)
<S>                                              <C>                   <C>               <C>                 <C>
OPERATING REVENUES:
    Electricity Marketing and Trading            $276,723              $396,250          $586,880            $809,383
    Energy Delivery                                31,385                30,837            66,514              67,164
    Sales to AEP Affiliates                         8,893                12,044            14,915              21,741
                                                 --------              --------          --------            --------

           TOTAL OPERATING REVENUES               317,001               439,131           668,309             898,288
                                                 --------              --------          --------            --------

OPERATING EXPENSES:
   Fuel                                            17,570                17,418            39,337              35,374
   Purchased Power:
      Electricity Marketing and Trading           224,647               349,388           476,652             707,618
      AEP Affiliates                               32,366                32,525            61,307              68,160
   Other Operation                                 12,811                14,470            25,280              29,198
   Maintenance                                      8,078                 5,185            12,627              10,614
   Depreciation and Amortization                    8,269                 8,080            16,526              16,107
   Taxes Other Than Income Taxes                    2,368                 1,900             4,503               3,949
   Income Taxes                                     1,342                 1,801             7,043               6,300
                                                 --------              --------          --------            --------

           TOTAL OPERATING EXPENSES               307,451               430,767           643,275             877,320
                                                 --------              --------          --------            --------

OPERATING INCOME                                    9,550                 8,364            25,034              20,968

NONOPERATING INCOME                               108,733               158,973           210,717             272,489

NONOPERATING EXPENSES                             104,604               157,076           205,516             268,349

NONOPERATING INCOME TAX EXPENSE                     1,920                   654             1,730               1,422

INTEREST CHARGES                                    6,513                 6,865            13,013              13,869
                                                 --------              --------          --------            --------

NET INCOME                                       $  5,246              $  2,742          $ 15,492            $  9,817
                                                 ========              ========          ========            ========
</TABLE>
<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                         Three Months Ended June 30,              Six Months Ended June 30,
                                           2002                2001                2002                2001
                                           ----                ----                ----                ----
                                                                 (in thousands)
<S>                                       <C>                 <C>                <C>                <C>
NET INCOME                                $5,246              $2,742             $15,492            $ 9,817

OTHER COMPREHENSIVE INCOME (LOSS)
    Cash Flow Power Hedge                    572                -                    572               -
    Cash Flow Interest Rate Hedge            357                 (68)                873             (1,422)
                                          ------              ------             -------            -------

COMPREHENSIVE INCOME                      $6,175              $2,674             $16,937            $ 8,395
                                          ======              ======             =======            =======
</TABLE>
The  common  stock of KPCo is  wholly  owned  by AEP.  See  Notes  to  Financial
Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                             KENTUCKY POWER COMPANY
                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                  Three Months Ended June 30,               Six Months Ended June 30,
                                     2002                2001                  2002              2001
                                     ----                ----                  ----              ----
                                                        (in thousands)
<S>                                <C>                 <C>                   <C>              <C>
BALANCE AT BEGINNING OF PERIOD     $52,035             $57,027               $48,833          $57,513

NET INCOME                           5,246               2,742                15,492            9,817

DEDUCTIONS:
Cash Dividends Declared              7,044               7,561                14,088           15,122
                                   -------             -------               -------          -------

BALANCE AT END OF PERIOD           $50,237             $52,208               $50,237          $52,208
                                   =======             =======               =======          =======
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                             KENTUCKY POWER COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                  June 30, 2002           December 31, 2001
                                                  -------------           -----------------
                                                                     (in thousands)
<S>                                                        <C>                        <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                              $  273,037                 $  271,070
   Transmission                                               373,339                    374,116
   Distribution                                               405,503                    402,537
   General                                                     63,671                     65,059
   Construction Work in Progress                               59,796                     15,633
                                                           ----------                 ----------
        Total Electric Utility Plant                        1,175,346                  1,128,415
   Accumulated Depreciation and Amortization                  394,818                    384,104
                                                           ----------                 ----------
          NET ELECTRIC UTILITY PLANT                          780,528                    744,311
                                                           ----------                 ----------

OTHER PROPERTY AND INVESTMENTS                                  6,354                      6,492
                                                           ----------                 ----------

LONG-TERM ENERGY TRADING CONTRACTS                            126,702                     77,972
                                                           ----------                 ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                      918                      1,947
   Advances to Affiliates                                       2,165                       -
   Accounts Receivable:
      Customers                                                23,516                     20,036
      Affiliated Companies                                     40,179                     16,012
      Miscellaneous                                             2,707                      3,333
      Allowance for Uncollectible Accounts                       (241)                      (264)
   Fuel - at average cost                                      17,479                     12,060
   Materials and Supplies - at average cost                    16,828                     15,766
   Accrued Utility Revenues                                     7,813                      5,395
   Energy Trading Contracts                                   204,908                    139,605
   Prepayments                                                  3,212                      1,314
                                                           ----------                 ----------
          TOTAL CURRENT ASSETS                                319,484                    215,204
                                                           ----------                 ----------

REGULATORY ASSETS                                              97,615                     97,692
                                                           ----------                 ----------

DEFERRED CHARGES                                               10,217                     11,572
                                                           ----------                 ----------

          TOTAL ASSETS                                     $1,340,900                 $1,153,243
                                                           ==========                 ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                             KENTUCKY POWER COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)


                                                     June 30, 2002           December 31, 2001
                                                     -------------           -----------------
                                                                       (in thousands)
<S>                                                           <C>                      <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - $50 Par Value:
      Authorized - 2,000,000 Shares
      Outstanding - 1,009,000 Shares                          $   50,450               $   50,450
   Paid-in Capital                                               158,750                  158,750
   Accumulated Other Comprehensive Income (Loss)                    (458)                  (1,903)
   Retained Earnings                                              50,237                   48,833
                                                              ----------               ----------
        Total Common Shareowner's Equity                         258,979                  256,130
   Long-term Debt                                                300,796                  251,093
                                                              ----------               ----------

           TOTAL CAPITALIZATION                                  559,775                  507,223
                                                              ----------               ----------

OTHER NONCURRENT LIABILITIES                                      12,348                   11,929
                                                              ----------               ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                            155,000                   95,000
   Advances from Affiliates                                         -                      66,200
   Accounts Payable:
      General                                                     32,325                   24,050
      Affiliated Companies                                        38,892                   22,557
   Customer Deposits                                               6,877                    4,461
   Taxes Accrued                                                  10,434                   10,305
   Interest Accrued                                                4,644                    5,269
   Energy Trading Contracts                                      203,518                  144,364
   Other                                                          14,981                   12,296
                                                              ----------               ----------

           TOTAL CURRENT LIABILITIES                             466,671                  384,502
                                                              ----------               ----------

DEFERRED INCOME TAXES                                            169,770                  168,304
                                                              ----------               ----------

DEFERRED INVESTMENT TAX CREDITS                                    9,814                   10,405
                                                              ----------               ----------

LONG-TERM ENERGY TRADING CONTRACTS                               111,507                   63,412
                                                              ----------               ----------

DEFERRED CREDITS                                                  11,015                    7,468
                                                              ----------               ----------

CONTINGENCIES (Note 8)

           TOTAL CAPITALIZATION AND LIABILITIES               $1,340,900               $1,153,243
                                                              ==========               ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                             KENTUCKY POWER COMPANY
                            STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                                 Six Months Ended June 30,
                                                                               2002                    2001
                                                                               ----                    ----
                                                                                    (in thousands)
<S>                                                                        <C>                      <C>
OPERATING ACTIVITIES:
   Net Income                                                              $ 15,492                 $  9,817
   Adjustments for Noncash Items:
      Depreciation and Amortization                                          16,526                   16,107
      Deferred Income Taxes                                                     965                    7,921
      Deferred Investment Tax Credits                                          (591)                    (593)
      Deferred Fuel Costs (net)                                               2,430                   (1,241)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                             (27,044)                   4,012
      Fuel, Materials and Supplies                                           (6,481)                    (672)
      Accrued Utility Revenues                                               (2,418)                   6,500
      Accounts Payable                                                       24,610                    3,245
      Taxes Accrued                                                             129                   (6,606)
   Mark-to-Market Energy Contracts                                           (4,479)                 (21,923)
   Change in Other Assets                                                    (1,416)                   2,336
   Change in Other Liabilities                                                6,355                   (4,841)
                                                                           --------                 --------
           Net Cash Flows From Operating Activities                          24,078                   14,062
                                                                           --------                 --------

INVESTING ACTIVITIES:
      Construction Expenditures                                             (51,997)                 (14,912)
      Proceeds from Sales of Property                                          -                         216
                                                                           --------                 --------
           Net Cash Flow Used For Investing Activities                      (51,997)                 (14,696)
                                                                           --------                 --------

FINANCING ACTIVITIES:
      Issuance of Long-term Debt - Affiliated Company                       123,843                   75,000
      Retirement of Long-term Debt                                          (14,500)                 (60,000)
      Change in Advances from Affiliates (net)                              (68,365)                    (405)
      Dividends Paid                                                        (14,088)                 (15,122)
                                                                           --------                 --------
           Net Cash Flows From (Used For) Financing Activities               26,890                     (527)
                                                                           --------                 --------

Net Decrease in Cash and Cash Equivalents                                    (1,029)                  (1,161)
Cash and Cash Equivalents at Beginning of Period                              1,947                    2,270
                                                                           --------                 --------
Cash and Cash Equivalents at End of Period                                 $    918                 $  1,109
                                                                           ========                 ========
</TABLE>
Supplemental Disclosure:
Cash  paid  for  interest  net  of  capitalized   amounts  was  $13,485,000  and
$13,692,000 and for income taxes was $7,024,000 and $6,010,000 in 2002 and 2001,
respectively.  Noncash  acquisitions  under  capital  leases  were  $22,021  and
$760,000 in 2002 and 2001, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
                       OHIO POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

         OPCo is a public utility  engaged in the  generation,  sale,  purchase,
transmission  and  distribution  of  electric  power  to  approximately  698,000
customers in the  northwestern,  east central,  eastern and southern sections of
Ohio. As a member of the AEP Power Pool,  OPCo shares the revenues and the costs
of the AEP Power  Pool's  wholesale  sales to  neighboring  utilities  and power
marketers including power trading transactions.  OPCo also sells wholesale power
to municipalities and electric cooperatives.
       The cost of the AEP System's  generating  capacity is allocated among the
AEP Power Pool  members  based on their  relative  peak  demands and  generating
reserves  through the  payment of  capacity  charges and the receipt of capacity
credits. AEP Power Pool members are also compensated for the out-of-pocket costs
of energy  delivered to the AEP Power Pool and charged for energy  received from
the AEP Power Pool. The AEP Power Pool  calculates  each company's  prior twelve
month peak demand relative to the total peak demand of all member companies as a
basis for sharing  revenues and costs.  The result of this  calculation  is each
company's  member load ratio (MLR) which  determines  each company's  percentage
share of revenues and costs.

Critical Accounting Policies - Revenue Recognition
Regulatory   Accounting  -  As  a  result  of  our   cost-based   rate-regulated
transmission and distribution  operations,  our financial statements reflect the
actions  of  regulators  that can  result in the  recognition  of  revenues  and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities  (future revenue  reductions or refunds) are recorded to reflect the
economic effects of regulation by matching  expenses with their recovery through
regulated revenues in the same accounting period.
         When  regulatory  assets are  probable  of recovery  through  regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation.  If we determine that recovery of a regulatory asset
is no longer  probable,  we write off that regulatory  asset as a charge against
net income.  A write off of regulatory  assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general expenses are recorded when incurred.
<PAGE>
Energy Marketing and Trading  Activities - AEP engages in wholesale  electricity
marketing  and  trading  transactions  (trading  activities).  A portion  of the
revenues and costs of AEP's trading activities are allocated to OPCo as a member
of the AEP Power  Pool.  Trading  activities  involve the  purchase  and sale of
energy under  physical  forward  contracts at fixed and variable  prices and the
buying and selling of financial  energy  contracts which include exchange traded
futures and options and  over-the-counter  options and swaps.  Although  trading
contracts are generally short-term,  there are also long-term trading contracts.
We recognize revenues from trading activities  generally based on changes in the
fair value of open energy trading contracts.
           Recording the net change in the fair value of open trading  contracts
prior to settlement is commonly referred to as mark-to-market  (MTM) accounting.
Under MTM  accounting  the change in the  unrealized  gain or loss  throughout a
contract's  term is  recognized  in each  accounting  period.  When the contract
actually  settles,  that is,  the  energy  is  actually  delivered  in a sale or
received in a purchase or the parties  agree to forego  delivery and receipt and
net  settle in cash,  the  unrealized  gain or loss is  reversed  and the actual
realized cash gain or loss is recognized. Therefore, over the trading contract's
term an unrealized  gain or loss is recognized  as the  contract's  market value
changes.  When the  contract  settles the total gain or loss is realized in cash
but only the difference  between the accumulated  unrealized net gains or losses
recorded  in  prior  months  and the cash  proceeds  is  recognized.  Unrealized
mark-to-market  gains and losses are  included  in the  Balance  Sheet as energy
trading contract assets or liabilities.
           The majority of our trading  activities  represent  physical  forward
electricity  contracts  that are typically  settled by entering into  offsetting
contracts.  An example of our trading  activities is when, in January,  we enter
into a forward sales contract to deliver electricity in July. At the end of each
month  until the  contract  settles  in July,  we would  record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of a gain
or loss in cash and reverse the previously recorded  cumulative  unrealized gain
or loss.
           Depending on whether the  delivery  point for the  electricity  is in
AEP's  traditional  marketing  area or not  determines  where  the  contract  is
reported on OPCo's income statement.  AEP's traditional  marketing area is up to
two  transmission  systems  from the AEP  service  territory.  Physical  forward
trading sale contracts with delivery points in AEP's traditional  marketing area
are included in revenues when the contracts  settle.  Physical  forward  trading
purchase contracts with delivery points in AEP's traditional  marketing area are
included in  purchased  power  expense when they  settle.  Prior to  settlement,
changes in the fair value of physical  forward  sale and  purchase  contracts in
AEP's  traditional  marketing  area are  included  in  revenues  on a net basis.
Physical  forward  sales  contracts  for delivery  outside of AEP's  traditional
marketing area are included in  nonoperating  income when the contract  settles.
Physical  forward purchase  contracts for delivery outside of AEP's  traditional
marketing area are included in nonoperating  expenses when the contract settles.
Prior to  settlement,  changes in the fair value of  physical  forward  sale and
purchase  contracts with delivery points outside of AEP's traditional  marketing
area are included in nonoperating income on a net basis.
<PAGE>
        Continuing  with the above  example,  assume  that  later in  January or
sometime in February  through July we enter into an offsetting  forward contract
to buy  electricity  in July. If we do nothing else with these  contracts  until
settlement in July and if the volumes,  delivery  point,  schedule and other key
terms match then the  difference  between the sale price and the purchase  price
represents a fixed value to be realized  when the  contracts  settle in July. If
the purchase  contract is perfectly  matched  with the sales  contract,  we have
effectively fixed the profit or loss;  specifically it is the difference between
the contracted settlement price of the two contracts.  Mark-to-market accounting
for these  contracts  from this point  forward  will have no  further  impact on
results of operations  but will have an  offsetting  and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase  contract prior to entering into a sales contract.  If
the sale and  purchase  contracts do not match  exactly as to volumes,  delivery
point,   schedule  and  other  key  terms,   then  there  could  be   continuing
mark-to-market  effects on  results  of  operations  from  recording  additional
changes in fair values using mark-to-market accounting.
        Trading of electricity  options,  futures and swaps represents financial
transactions  with  unrealized  gains and losses  from  changes  in fair  values
reported net in  nonoperating  income  until the  contracts  settle.  When these
financial  contracts  settle,  we  record  our  share  of the  net  proceeds  in
nonoperating  income and  reverse to  nonoperating  income the prior  cumulative
unrealized net gain or loss.
        The  fair  value  of open  short-term  trading  contracts  are  based on
exchange  prices and broker quotes.  We  mark-to-market  open long-term  trading
contracts based mainly on AEP-developed  valuation models. These models estimate
future energy  prices based on existing  market and broker quotes and supply and
demand market data and  assumptions.  The fair values  determined are reduced by
reserves to adjust for credit risk and liquidity  risk.  Credit risk is the risk
that the  counterparty  to the  contract  will  fail to  perform  or fail to pay
amounts due AEP.  Liquidity risk represents the risk that  imperfections  in the
market  will cause the price to be less than or more than what the price  should
be based purely on supply and demand.  There are inherent  risks  related to the
underlying  assumptions  in models  used to fair  value open  long-term  trading
contracts.  AEP has independent  controls to evaluate the  reasonableness of our
valuation models. However,  energy markets,  especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ  from  actual  prices  throughout  a  contract's  term and when
contracts  settle.  Therefore,  there could be significant  adverse or favorable
effects on future  results  of  operations  and cash  flows if market  prices at
settlement do not correlate with the AEP-developed price models.
        Volatility in commodities  markets affects the fair values of all of our
open trading  contracts  exposing  OPCo to market risk.  See  "Quantitative  and
Qualitative  Disclosures  about  Market Risk"  section for a  discussion  of the
policies and procedures used to manage exposure to risk from trading activities.

Results of Operations
        Net income  increased  $44.8  million in the second  quarter of 2002 and
$55.4 million in the  year-to-date  period due to the effect of an extraordinary
loss  recorded  in the second  quarter  of 2001 to  recognize  a stranded  asset
resulting from deregulation.

<PAGE>

        The  decline  in  revenues  is  mainly  due to a  decrease  in  electric
marketing and trading revenues due to lower wholesale energy prices. In 2002 the
wholesale  energy sector has been under pressure from lower commodity  prices in
contrast to last year when we had strong performance from the wholesale business
due to favorable market conditions.
        The following analyzes the changes in operating revenues:
<TABLE>
<CAPTION>
                                                                  Increase (Decrease)
                                             Second Quarter                              Year-to-Date
                                     (in millions)            %              (in millions)                  %
                                                              -                                             -
<S>                                         <C>             <C>                     <C>                   <C>
       Electricity Marketing
        and Trading*                        $(337)          (25)                    $(632)                (23)
       Energy Delivery*                        10             7                        20                   8
       Sales to AEP Affiliates                 (4)           (3)                      (36)                (13)
                                            -----                                   -----
            Total                           $(331)          (20)                    $(648)                (19)
                                            =====                                   =====
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.

        Operating expenses declined 22% in the second quarter of 2002 and 21% in
the  year-to-date  period of 2002.  The changes in the  components  of operating
expenses were:
<TABLE>
<CAPTION>
                                                                     Increase (Decrease)
                                                     Second Quarter                          Year-to-Date
                                            (in millions)           %         (in millions)                 %
                                                                    -                                       -
<S>                                                <C>            <C>                <C>                  <C>
       Fuel                                         $(31)         (17)               $ (89)               (23)
       Electricity Marketing
        and Trading Purchases                       (341)         (30)                (623)               (27)
       Purchases from AEP Affiliates                   4           22                    1                  4
       Other Operation                                10           10                   12                  7
       Maintenance                                    (7)         (18)                 (13)               (18)
       Depreciation and Amortization                   3            6                    6                  5
       Taxes Other Than Income Taxes                  (1)          (3)                   4                  5
       Income Taxes                                   17           94                   21                 42
                                                    ----                             -----
            Total                                  $(346)         (22)               $(681)               (21)
                                                   =====                             =====
</TABLE>
        The fuel  expense  decrease  reflects a reduction  of 17% in the average
cost fuel for generation offset in part by a 10% increase in MWH generated.
        Electricity  marketing  and  trading  purchases  declined  due to  lower
wholesale  energy costs  driven by market  conditions.
        Other operation expense increased in both periods primarily due to post
retirement benefits expense.
        Maintenance  expenses decreased in the second quarter and year-to-date
of 2002 due to boiler overhaul work that was performed during 2001.
        Depreciation  expense  increased in both periods due to the placement of
selective  catalytic reduction (SCR) technology in service at the Gavin Plant in
the second quarter of 2001.
        The increase in income taxes for both periods is predominately due to an
increase in pre-tax income.
        The  decrease  in   nonoperating   income  as  well  as  a  decrease  in
nonoperating  expenses  was due to a reduction  in net gains from AEP Power Pool
trading transactions outside of the AEP System's traditional marketing area. The
AEP Power Pool enters into power trading  transactions for the purchase and sale
of electricity  and for options,  futures and swaps.  The Company's share of the
AEP Power Pool's gains and losses from forward electricity trading  transactions
outside  of the AEP  System  traditional  marketing  area  and  for  speculative

<PAGE>

financial  transactions  (options,  futures,  swaps) is included in nonoperating
income and expense.  The decrease reflects a reduction in electricity prices and
margins due to a decrease in demand.
        The  decrease  in  interest  was  primarily  due to a  slightly  smaller
decrease  in the  outstanding  balances  of  long-term  debt in both  periods as
compared  to year end  balances  in both  periods,  the  refinancing  of debt at
favorable interest rates and a reduction in short-term interest rates.
<PAGE>
<TABLE>
<CAPTION>
                       OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                  Three Months Ended June 30,            Six Months Ended June 30,
                                                  2002                 2001               2002                2001
                                                  ----                 ----               ----                ----
                                                                        (in thousands)
<S>                                            <C>                 <C>                <C>                <C>
OPERATING REVENUES:
    Electricity Marketing and Trading          $1,027,105          $1,364,271         $2,159,297         $2,791,088
    Energy Delivery                               143,144             133,160            284,904            265,009
    Sales to AEP Affiliates                       125,393             129,746            235,027            270,745
                                               ----------          ----------         ----------         ----------

           TOTAL OPERATING REVENUES             1,295,642           1,627,177          2,679,228          3,326,842
                                               ----------          ----------         ----------         ----------

OPERATING EXPENSES:
   Fuel                                           149,097             180,057            291,433            380,618
   Purchased Power:
      Electricity Marketing and Trading           789,191           1,130,038          1,669,348          2,292,322
      AEP Affiliates                               20,265              16,617             34,492             33,239
   Other Operation                                106,633              96,623            197,153            185,029
   Maintenance                                     29,957              36,448             58,945             71,848
   Depreciation and Amortization                   61,176              57,666            123,797            117,725
   Taxes Other Than Income Taxes                   43,292              44,662             89,131             84,898
   Income Taxes                                    34,985              17,999             70,167             49,340
                                               ----------          ----------         ----------         ----------

           TOTAL OPERATING EXPENSES             1,234,596           1,580,110          2,534,466          3,215,019
                                               ----------          ----------         ----------         ----------

OPERATING INCOME                                   61,046              47,067            144,762            111,823
NONOPERATING INCOME                               381,184             538,032            737,525            908,506
NONOPERATING EXPENSES                             366,062             528,734            716,885            885,592
NONOPERATING INCOME TAX EXPENSE                       626               1,489              4,348              3,997
INTEREST CHARGES                                   20,194              22,782             41,655             45,249
                                               ----------          ----------         ----------         ----------
INCOME BEFORE EXTRAORDINARY ITEM                   55,348              32,094            119,399             85,491
EXTRAORDINARY LOSS - EFFECTS OF
 DEREGULATION (INCLUSIVE OF TAX BENEFIT
 OF $11,585,000)                                     -                (21,515)             -                (21,515)
                                               ----------          ----------          --------          ----------

NET INCOME                                         55,348              10,579           119,399              63,976

PREFERRED STOCK DIVIDEND REQUIREMENTS                 315                 316               629                 630
                                               ----------          ----------          --------          ----------

EARNINGS APPLICABLE TO COMMON STOCK            $   55,033          $   10.263          $118,770          $   63,346
                                               ==========          ==========          ========          ==========
</TABLE>
<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                            Three Months Ended June 30,              Six Months Ended June 30,
                                              2002                 2001                  2002              2001
                                              ----                 ----                  ----              ----
                                                                     (in thousands)
<S>                                         <C>                  <C>                   <C>              <C>
NET INCOME                                  $55,348              $10,579               $119,399         $63,976

OTHER COMPREHENSIVE INCOME (LOSS)
    Foreign Currency Exchange Rate Hedge       -                    -                      (201)           -
    Cash Flow Power Hedges                    1,970                 (104)                 1,970            (325)
                                            -------              -------               --------         -------

COMPREHENSIVE INCOME                        $57,318              $10,475               $121,168         $63,651
                                            =======              =======               ========         =======
</TABLE>
The common  stock of Ohio Power is wholly  owned by AEP.  See Notes to Financial
Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                       OHIO POWER COMPANY AND SUBSIDIARIES
                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                              Three Months Ended June 30,        Six Months Ended June 30,
                                             2002                2001                2002               2001
                                             ----                ----                ----               ----
                                                                              (in thousands)
<S>                                       <C>                  <C>                  <C>              <C>
BALANCE AT BEGINNING OF PERIOD            $432,452             $415,425             $401,297         $398,086

NET INCOME                                  55,348               10,579              119,399           63,976

CASH DIVIDENDS DECLARED:
    Common Stock                            32,582               35,744               65,164           71,488
    Cumulative Preferred Stock                 315                  315                  629              629
                                          --------             --------             --------         --------

BALANCE AT END OF PERIOD                  $454,903             $389,945             $454,903         $389,945
                                          ========             ========             ========         ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                       OHIO POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                            June 30, 2002           December 31, 2001
                                                            -------------           -----------------
                                                                           (in thousands)

<S>                                                              <C>                       <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                                    $3,032,034                $3,007,866
   Transmission                                                     891,591                   891,283
   Distribution                                                   1,095,478                 1,081,122
   General                                                          238,903                   245,232
   Construction Work in Progress                                    264,296                   165,073
                                                                 ----------                ----------
        Total Electric Utility Plant                              5,522,302                 5,390,576
   Accumulated Depreciation and Amortization                      2,513,727                 2,452,571
                                                                 ----------                ----------
          NET ELECTRIC UTILITY PLANT                              3,008,575                 2,938,005
                                                                 ----------                ----------

OTHER PROPERTY AND INVESTMENTS                                       59,958                    62,303
                                                                 ----------                ----------

LONG-TERM ENERGY TRADING CONTRACTS                                  438,789                   263,734
                                                                 ----------                ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                          6,872                     8,848
   Accounts Receivable:
      Customers                                                     103,425                    84,694
      Affiliated Companies                                          193,372                   148,563
      Miscellaneous                                                  22,937                    20,409
      Allowance for Uncollectible Accounts                             (678)                   (1,379)
   Fuel - at average cost                                            87,396                    84,724
   Materials and Supplies - at average cost                          81,625                    88,768
   Accrued Utility Revenues                                           5,276                      -
   Energy Trading Contracts                                         711,726                   472,246
   Prepayments and Other                                             36,624                    20,865
                                                                 ----------                ----------
          TOTAL CURRENT ASSETS                                    1,248,575                   927,738
                                                                 ----------                ----------

REGULATORY ASSETS                                                   611,696                   644,625
                                                                 ----------                ----------

DEFERRED CHARGES                                                     42,290                    79,662
                                                                 ----------                ----------

          TOTAL ASSETS                                           $5,409,883                $4,916,067
                                                                 ==========                ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                       OHIO POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                          June 30, 2002           December 31, 2001
                                                          -------------           -----------------
                                                                   (in thousands)
<S>                                                            <C>                        <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 40,000,000 Shares
      Outstanding - 27,952,473 Shares                          $  321,201                 $  321,201
   Paid-in Capital                                                462,483                    462,483
   Accumulated Other Comprehensive Income (Loss)                    1,573                       (196)
   Retained Earnings                                              454,903                    401,297
                                                               ----------                 ----------
        Total Common Shareholder's Equity                       1,240,160                  1,184,785
   Cumulative Preferred Stock:
      Not Subject to Mandatory Redemption                          16,648                     16,648
      Subject to Mandatory Redemption                               8,850                      8,850
   Long-term Debt                                                 974,350                  1,203,841
                                                               ----------                 ----------

           TOTAL CAPITALIZATION                                 2,240,008                  2,414,124
                                                               ----------                 ----------

OTHER NONCURRENT LIABILITIES                                      130,298                    130,386
                                                               ----------                 ----------

CURRENT LIABILITIES:
   Short-term Debt From Affiliated Companies                      150,000                       -
   Long-term Debt Due Within One Year                             224,850                       -
   Advances from Affiliates                                       137,069                    300,213
   Accounts Payable - General                                     131,398                    134,418
   Accounts Payable - Affiliated Companies                        274,557                    176,520
   Customer Deposits                                                9,037                      5,452
   Taxes Accrued                                                  141,044                    126,770
   Interest Accrued                                                21,965                     17,679
   Obligations Under Capital Leases                                14,346                     16,405
   Energy Trading Contracts                                       673,621                    456,047
   Other                                                           56,250                     87,070
                                                               ----------                 ----------

           TOTAL CURRENT LIABILITIES                            1,834,137                  1,320,574
                                                               ----------                 ----------

DEFERRED INCOME TAXES                                             781,270                    797,889
                                                               ----------                 ----------

DEFERRED INVESTMENT TAX CREDITS                                    20,395                     21,925
                                                               ----------                 ----------

LONG-TERM ENERGY TRADING CONTRACTS                                382,253                    214,487
                                                               ----------                 ----------

DEFERRED CREDITS                                                   21,522                     16,682
                                                               ----------                 ----------

CONTINGENCIES (Note 8)

       TOTAL CAPITALIZATION AND LIABILITIES                    $5,409,883                 $4,916,067
                                                               ==========                 ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                       OHIO POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                         Six Months Ended June 30,
                                                                         2002                  2001
                                                                         ----                  ----
                                                                              (in thousands)

OPERATING ACTIVITIES:
<S>                                                                    <C>                  <C>
   Net Income                                                          $ 119,399            $  63,976
   Adjustments for Noncash Items:
      Depreciation                                                        86,605               93,161
      Amortization of Transition Assets                                   37,192               36,705
      Deferred Federal Income Taxes                                      (18,653)                 116
      Mark-to-Market Energy Trading Contracts                            (24,493)             (69,557)
      Deferred Property Taxes                                             30,046               40,596
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                          (66,769)             (37,904)
      Fuel, Materials and Supplies                                         4,471                2,252
      Accrued Utility Revenues                                            (5,276)                 264
      Prepayments and Other Current Assets                               (15,759)              15,116
      Accounts Payable                                                    95,017              (62,996)
      Customer Deposits                                                    3,585              (32,368)
      Taxes Accrued                                                       14,274              (39,022)
      Interest Accrued                                                     4,286                3,841
   Other Operating Assets                                                  6,667               15,877
   Other Operating Liabilities                                           (30,834)             (44,004)
                                                                       ---------            ---------
           Net Cash Flows From (Used For) Operating Activities           239,758              (13,947)
                                                                       ---------            ---------

INVESTING ACTIVITIES:
      Construction Expenditures                                         (158,080)            (151,314)
      Proceeds from Sale of Property and Other                               283                7,626
                                                                       ---------            ---------
           Net Cash Flows Used For Investing Activities                 (157,797)            (143,688)
                                                                       ---------            ---------

FINANCING ACTIVITIES:
      Change in Advances to Affiliates (net)                            (163,144)             344,809
      Retirement of Long-term Debt                                        (5,000)            (117,506)
      Change in Short-term Debt Affiliated (net)                         150,000                 -
      Dividends Paid on Common Stock                                     (65,164)             (71,488)
      Dividends Paid on Cumulative Preferred Stock                          (629)                (630)
                                                                       ---------            ---------
           Net Cash Flows From (Used For) Financing Activities           (83,937)             155,185
                                                                       ---------            ---------

Net Decrease in Cash and Cash Equivalents                                 (1,976)              (2,450)
Cash and Cash Equivalents at Beginning of Period                           8,848               31,393
                                                                       ---------            ---------
Cash and Cash Equivalents at End of Period                             $   6,872            $  28,943
                                                                       =========            =========
</TABLE>
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $36,585,000 and
$40,580,000  and for income taxes was  $29,187,000  and  $54,694,000 in 2002 and
2001,  respectively.  Noncash acquisitions under capital leases were $98,000 and
$522,000 in 2002 and 2001, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

       PSO is a  public  utility  engaged  in the  generation,  purchase,  sale,
transmission and distribution of electric power to approximately  503,000 retail
customers in eastern and southwestern Oklahoma. PSO also sells electric power at
wholesale to other utilities, municipalities and rural electric cooperatives.
       Wholesale power  marketing and trading  activities are conducted on PSO's
behalf by AEPSC. PSO, along with the other AEP electric operating  subsidiaries,
shares in AEP's forward trades with other utility systems and power marketers.

Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a cost-based  rate-regulated  electric public utility
company,   PSO's  consolidated  financial  statements  reflect  the  actions  of
regulators  that can result in the  recognition  of  revenues  and  expenses  in
different  time  periods  than  enterprises  that  are not  rate  regulated.  In
accordance with SFAS 71,  regulatory  assets (deferred  expenses) and regulatory
liabilities  (future revenue  reductions or refunds) are recorded to reflect the
economic effects of regulation by matching  expenses with their recovery through
regulated revenues in the same accounting period.
        When regulatory assets are probable of recovery through regulated rates,
we record  them as assets  on the  balance  sheet.  We test for  probability  of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation.  If we determine that recovery of a regulatory asset
is no longer  probable,  we write off that regulatory  asset as a charge against
net income.  A write off of regulatory  assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general expenses are recorded when incurred.

Energy Marketing and Trading  Activities - AEP engages in wholesale  electricity
marketing  and  trading  transactions  (trading  activities).  A portion  of the
revenues and costs of AEP's trading  activities  are  allocated to PSO.  Trading
activities  allocated  to PSO  involve  the  purchase  and sale of energy  under
physical  forward  contracts  at fixed and  variable  prices.  Although  trading
contracts are generally short-term, there are also long-term trading contracts.


<PAGE>


           Accounting  standards  applicable to trading  activities require that
changes in the fair value of trading  contracts be recognized in revenues  prior
to settlement and is commonly  referred to as  mark-to-market  (MTM) accounting.
Since PSO is a cost-based  rate-regulated  entity,  whose  revenues are based on
settled  transactions,  unrealized changes in the fair value of physical forward
sale and purchase  contracts are deferred as regulatory  liabilities  (gains) or
regulatory assets (losses).
           Mark-to-market  accounting  represents  the change in the  unrealized
gain or loss throughout the contract's term. When the contract actually settles,
that is, the energy is actually delivered in a sale or received in a purchase or
the parties  agree to forego  delivery  and receipt and net settle in cash,  the
unrealized gain or loss is reversed and the actual realized cash gain or loss is
recognized in the income  statement.  Therefore,  as the contract's market value
changes over the  contract's  term an  unrealized  gain or loss is deferred as a
regulatory  liability or a regulatory asset. When the contract settles the total
gain  or loss is  realized  in cash  and  recognized  in the  income  statement.
Physical  forward  trading  sale  contracts  are  included in revenues  when the
contracts  settle.  Physical forward trading purchase  contracts are included in
purchased  power expense when they settle.  Prior to settlement,  changes in the
fair value of physical  forward  sale and  purchase  contracts  are  deferred as
regulatory  liabilities  (gains)  or  regulatory  assets  (losses).   Unrealized
mark-to-market  gains and losses are  included  in the  Balance  Sheet as energy
trading contract assets or liabilities.
        The  fair  value  of open  short-term  trading  contracts  are  based on
exchange  prices and broker quotes.  We  mark-to-market  open long-term  trading
contracts based mainly on AEP-developed  valuation models. These models estimate
future energy  prices based on existing  market and broker quotes and supply and
demand market data and  assumptions.  The fair values  determined are reduced by
reserves to adjust for credit risk and liquidity  risk.  Credit risk is the risk
that the  counterparty  to the  contract  will  fail to  perform  or fail to pay
amounts due. Liquidity risk represents the risk that imperfections in the market
will cause the price to be less than or more than what the price should be based
purely on supply and demand.  There are inherent risks related to the underlying
assumptions in models used to fair value open long-term trading  contracts.  AEP
has independent controls to evaluate the reasonableness of our valuation models.
However,  energy  markets,  especially  electricity  markets,  are imperfect and
volatile and  unforeseen  events can and will cause  reasonable  price curves to
differ  from actual  prices  throughout  a  contract's  term and when  contracts
settle.  Therefore,  there could be significant  adverse or favorable effects on
future  results of  operations  and cash flows if market prices at settlement do
not correlate with the AEP-developed price models.
       Volatility in commodities  markets  affects the fair values of all of our
open  trading  contracts  exposing  PSO to market risk.  See  "Quantitative  and
Qualitative  Disclosures  about  Market Risk"  section for a  discussion  of the
policies and procedures used to manage exposure to risk from trading activities.

Results of Operations
         Net income declined by 2.5% for the quarter and 4% for the year-to-date
period as  substantial  decreases in revenues  were nearly  offset by comparable
decreases in operating expenses.
<PAGE>
The following analyzes the changes in operating revenues:
<TABLE>
<CAPTION>
                                                                   Increase (Decrease)
                                              Second Quarter                              Year-to-Date
                                       (in millions)           %              (in millions)                  %
                                                               -                                             -
<S>                                          <C>             <C>                     <C>                   <C>
       Electricity Marketing
        and Trading*                         $(153)          (47)                    $(256)                (41)
       Energy Delivery*                         10            16                        13                  12
       Sales to AEP Affiliates                  (2)          (19)                      (11)                (56)
                                             -----                                   -----
            Total                            $(145)          (36)                    $(254)                (34)
                                             =====                                   =====
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.

         Operating  revenues decreased as a result of a decline in fuel recovery
revenue and a decline in AEP  marketing  and trading  revenues  shared with PSO.
Revenues from AEP's power marketing and trading operations  declined as a result
of lower prices for wholesale power  transactions.  In 2002 the wholesale energy
sector has been under pressure from lower  commodity  prices in contrast to last
year when we had strong performance from the wholesale business due to favorable
market conditions.
         Significant change in operating expenses are as follows:
<TABLE>
<CAPTION>
                                                                                      Increase (Decrease)
                                                                     Second Quarter                           Year-to-Date
                                                              (in millions)            %         (in millions)               %
                                                                                       -                                     -
<S>                                                                  <C>             <C>                <C>                <C>
       Fuel                                                          $(112)          (77)               $(166)             (64)
       Electricity Marketing
        and Trading Purchases                                          (44)          (35)                 (77)             (30)
       Purchases from AEP Affiliates                                    12            53                   (8)             (14)
       Other Operation                                                  -              -                   (7)             (11)
       Maintenance                                                      (1)           (8)                   3               15
       Depreciation and Amortization                                     1             7                    3                7
</TABLE>
         The  decrease in fuel  expense was  primarily  due to  amortization  of
previously  overrecovered  fuel costs through the fuel clause recovery mechanism
and a reduction in the cost of fuel  reflecting  lower market prices for natural
gas and fuel oil.
         The  decrease in electric  marketing  and  trading  purchases  resulted
mainly from the decrease in energy prices.
         The increase in the quarter and the decrease  year-to-date in purchases
from AEP affiliates results mainly from the availability of internal generation.
         Other operation expense decreased in the year-to-date period primarily
due to lower transmission, administrative, and customer service expenses.
         Maintenance  expense  decreased in the second  quarter due primarily to
lower  production  power plant costs and  distribution  costs for  overhead  and
underground facilities.  Year-to-date maintenance expense increased largely as a
result of  increased  expenses to repair  damage to overhead  lines  caused by a
winter storm in 2002.
         Depreciation  expense  increased for both the quarter and  year-to-date
due to the cost of repowering Northeast Station Units 1 & 2.
<PAGE>
<TABLE>
<CAPTION>
               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                  Three Months Ended June 30,            Six Months Ended June 30,
                                                  2002                  2001              2002                2001
                                                  ----                  ----              ----                ----
                                                                        (in thousands)
<S>                                             <C>                 <C>                 <C>              <C>
OPERATING REVENUES:
    Electricity Marketing and Trading           $175,999            $  329,316          $370,023         $  625,915
    Energy Delivery                               70,815                61,294           122,547            109,711
    Sales to AEP Affiliates                        6,162                 7,584             8,256             18,707
                                                --------            ----------          --------         ----------

           TOTAL OPERATING REVENUES              252,976               398,194           500,826            754,333
                                                --------            ----------          --------         ----------

OPERATING EXPENSES:
   Fuel                                           33,772               145,927            91,869            257,728
   Purchased Power:
      Electricity Marketing and Trading           81,803               126,602           178,323            255,781
      AEP Affiliates                              34,703                22,659            51,548             60,026
   Other Operation                                34,826                34,332            61,465             68,889
   Maintenance                                    11,886                12,859            26,055             22,689
   Depreciation and Amortization                  21,061                19,673            41,977             39,144
   Taxes Other Than Income Taxes                   8,083                 7,533            15,931             15,326
   Income Taxes                                    6,641                 6,667             5,047              4,468
                                                --------            ----------          --------         ----------

           TOTAL OPERATING EXPENSES              232,775               376,252           472,215            724,051
                                                --------            ----------          --------         ----------

OPERATING INCOME                                  20,201                21,942            28,611             30,282

NONOPERATING INCOME                                1,223                   409             1,329              1,233

NONOPERATING EXPENSES                                 69                   336               664                672

NONOPERATING INCOME TAX CREDIT                      (100)                  (19)             (241)              (134)

INTEREST CHARGES                                   9,835                10,113            19,545             20,616
                                                --------            ----------          --------         ----------

NET INCOME                                        11,620                11,921             9,972             10,361

PREFERRED STOCK DIVIDEND REQUIREMENTS                 53                    53               106                106
                                                --------            ----------          --------         ----------

EARNINGS APPLICABLE TO COMMON STOCK             $ 11,567            $   11.868          $  9,866         $   10,255
                                                ========            ==========          ========         ==========
</TABLE>
<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                   Three Months Ended June 30,              Six Months Ended June 30,
                                     2002                2001                  2002              2001
                                     ----                ----                  ----              ----
                                                           (in thousands)
<S>                                <C>                 <C>                   <C>              <C>
NET INCOME                         $11,620             $11,921               $ 9,972          $10,361

OTHER COMPREHENSIVE INCOME
    Cash Flow Power Hedge              200                -                      200             -
                                   -------             -------               -------          -------

COMPREHENSIVE INCOME               $11,820             $11,921               $10,172          $10,361
                                   =======             =======               =======          =======
</TABLE>
The common  stock of the Company is wholly  owned by AEP. See Notes to Financial
Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                  Three Months Ended June 30,                  Six Months Ended June 30,
                                           2002                2001                2002               2001
                                           ----                ----                ----               ----
                                                                              (in thousands)
<S>                                     <C>                  <C>                 <C>               <C>
BALANCE AT BEGINNING OF PERIOD          $118,838             $123,015            $142,994          $137,688
NET INCOME                                11,620               11,921               9,972            10,361
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                          22,456               13,060              44,911            26,120
    Preferred Stock                           53                   53                 106               106
                                        --------             --------            --------          --------

BALANCE AT END OF PERIOD                $107,949             $121,823            $107,949          $121,823
                                        ========             ========            ========          ========
</TABLE>
The common  stock of the Company is wholly  owned by AEP. See Notes to Financial
Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                            June 30, 2002           December 31, 2001
                                                            -------------           -----------------
                                                                           (in thousands)
<S>                                                               <C>                      <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                                     $1,040,461               $1,034,711
   Transmission                                                      432,990                  427,110
   Distribution                                                      990,374                  972,806
   General                                                           203,088                  203,572
   Construction Work in Progress                                      58,004                   56,900
                                                                  ----------               ----------
          Total Electric Utility Plant                             2,724,917                2,695,099
   Accumulated Depreciation and Amortization                       1,219,697                1,184,443
                                                                  ----------               ----------
        NET ELECTRIC UTILITY PLANT                                 1,505,220                1,510,656
                                                                  ----------               ----------

OTHER PROPERTY AND INVESTMENTS                                        42,383                   41,020
                                                                  ----------               ----------

LONG-TERM ENERGY TRADING CONTRACTS                                    22,015                   55,215
                                                                  ----------               ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                           6,953                    5,795
   Accounts Receivable:
      Customers                                                       35,896                   31,100
      Affiliated Companies                                            30,061                   10,905
   Fuel - at LIFO costs                                               24,939                   21,559
   Materials and Supplies - at average costs                          36,631                   36,785
   Under-Recovered Fuel Costs                                         44,436                     -
   Energy Trading Contracts                                           41,417                  162,200
   Prepayments and Other                                               2,343                    2,368
                                                                  ----------               ----------
          TOTAL CURRENT ASSETS                                       222,676                  270,712
                                                                  ----------               ----------

REGULATORY ASSETS                                                     26,428                   35,004
                                                                  ----------               ----------

DEFERRED CHARGES                                                      26,152                    5,290
                                                                  ----------               ----------

          TOTAL ASSETS                                            $1,844,874               $1,917,897
                                                                  ==========               ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                                 June 30, 2002            December 31, 2001
                                                                 -------------            -----------------
                                                                                (in thousands)
<S>                                                                    <C>                       <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - $15 Par Value:
      Authorized Shares: 11,000,000 Shares
      Issued Shares: 10,482,000 shares and
      Outstanding Shares: 9,013,000 Shares                             $  157,230                $  157,230
   Paid-in Capital                                                        180,000                   180,000
   Accumulated Other Comprehensive Income                                     200                      -
   Retained Earnings                                                      107,949                   142,994
                                                                       ----------                ----------
        Total Common Shareholder's Equity                                 445,379                   480,224
   Cumulative Preferred Stock Not Subject
    to Mandatory Redemption                                                 5,283                     5,283
   PSO-Obligated, Mandatorily Redeemable Preferred
    Securities of Subsidiary Trust Holding Solely Junior
    Subordinated Debentures of PSO                                         75,000                    75,000
   Long-term Debt                                                         310,283                   345,129
                                                                       ----------                ----------

           TOTAL CAPITALIZATION                                           835,945                   905,636
                                                                       ----------                ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                     141,000                   106,000
   Advances from Affiliates                                               212,950                   123,087
   Accounts Payable - General                                              62,987                    72,759
   Accounts Payable - Affiliated Companies                                 76,447                    40,857
   Customers Deposits                                                      21,869                    21,041
   Taxes Accrued                                                           15,962                    18,150
   Over-Recovered Fuel Costs                                                 -                        8,720
   Interest Accrued                                                         3,331                     7,298
   Energy Trading Contracts                                                47,305                   167,658
   Other                                                                   17,262                    12,296
                                                                       ----------                ----------

           TOTAL CURRENT LIABILITIES                                      599,113                   577,866
                                                                       ----------                ----------

DEFERRED INCOME TAXES                                                     319,339                   296,877
                                                                       ----------                ----------

DEFERRED INVESTMENT TAX CREDITS                                            33,097                    33,992
                                                                       ----------                ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                37,170                    56,203
                                                                       ----------                ----------

LONG-TERM ENERGY TRADING CONTRACTS                                         20,210                    47,323
                                                                       ----------                ----------

           TOTAL CAPITALIZATION AND LIABILITIES                        $1,844,874                $1,917,897
                                                                       ==========                ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                              Six Months Ended June 30,
                                                                              2002                 2001
                                                                              ----                 ----
                                                                               (in thousands)
<S>                                                                        <C>                  <C>
OPERATING ACTIVITIES:
   Net Income                                                              $   9,972             $ 10,361
   Adjustments for Noncash Items:
      Depreciation and Amortization                                           41,977               39,144
      Deferred Income Taxes                                                   21,559              (10,754)
      Deferred Investment Tax Credits                                           (895)                (895)
      Deferred Property Taxes                                                (16,184)             (14,951)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                              (23,952)              17,488
      Fuel, Materials and Supplies                                            (3,226)               6,094
      Accounts Payable                                                        25,818              (52,882)
      Taxes Accrued                                                           (2,188)              28,006
      Fuel Recovery                                                          (53,156)              31,748
   Changes in Other Assets                                                    (2,968)              (8,234)
   Changes in Other Liabilities                                               (4,387)               1,780
                                                                           ---------             --------
           Net Cash Flows From (Used For) Operating Activities                (7,630)              46,905
                                                                           ---------             --------

INVESTING ACTIVITIES:
      Construction Expenditures                                              (35,095)             (67,042)
      Other                                                                     (963)                (359)
                                                                           ---------             --------
           Net Cash Flows Used For Investing Activities                      (36,058)             (67,401)
                                                                           ---------             --------

FINANCING ACTIVITIES:
      Retirement of Long-term Debt                                              -                 (20,000)
      Change in Advances From Affiliates (net)                                89,863               66,327
      Dividends Paid on Common Stock                                         (44,911)             (26,120)
      Dividends Paid on Cumulative Preferred Stock                              (106)                (106)
                                                                           ---------             --------
           Net Cash Flows From Financing Activities                           44,846               20,101
                                                                           ---------             --------

Net Increase in Cash and Cash Equivalents                                      1,158                 (395)
Cash and Cash Equivalents at Beginning of Period                               5,795               11,301
                                                                           ---------             --------
Cash and Cash Equivalents at End of Period                                 $   6,953            $ 10,906
                                                                           =========            ========
</TABLE>
Supplemental Disclosure:
Cash  paid  for  interest  net  of  capitalized   amounts  was  $17,870,000  and
$19,011,000 and for income taxes was $2,575,000 and $1,978,000 in 2002 and 2001,
respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

         SWEPCo is a public utility engaged in the generation,  purchase,  sale,
transmission  and   distribution  of  electric  power  in  northeastern   Texas,
northwestern Louisiana,  and western Arkansas.  SWEPCo also sells electric power
at wholesale to other utilities, municipalities and rural electric cooperatives.
         Wholesale  power  marketing  and trading  activities  are  conducted on
SWEPCo's behalf by AEPSC.  SWEPCo,  along with the other AEP electric  operating
subsidiaries,  shares in AEP's  forward  trades with other  utility  systems and
power marketers.

Critical Accounting Policies - Revenue Recognition
Regulatory  Accounting  -  Our  financial  statements  reflect  the  actions  of
regulators since our electricity supply sales in the Louisiana  jurisdiction and
our transmission and distribution operations are cost-based rate-regulated. As a
result of the  regulators'  actions,  our  financial  statements  can  recognize
revenues and expenses in different  time periods than  enterprises  that are not
rate  regulated.  In  accordance  with  SFAS  71,  regulatory  assets  (deferred
expenses) and regulatory  liabilities (future revenue reductions or refunds) are
recorded to reflect the economic effects of regulation by matching expenses with
their recovery through regulated revenues in the same accounting period.

Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general expenses are recorded when incurred.
        When regulatory assets are probable of recovery through regulated rates,
we record  them as assets  on the  balance  sheet.  We test for  probability  of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation.  If we determine that recovery of a regulatory asset
is no longer  probable,  we write off that regulatory  asset as a charge against
net income.  A write off of regulatory  assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Energy Marketing and Trading  Activities - AEP engages in wholesale  electricity
marketing  and  trading  transactions  (trading  activities).  A portion  of the
revenues and costs of AEP's trading activities are allocated to SWEPCo.  Trading
activities  allocated  to SWEPCo  involve the  purchase and sale of energy under
physical  forward  contracts  at fixed and  variable  prices.  Although  trading
contracts are generally short-term,  there are also long-term trading contracts.
We generally recognize revenues from open trading activities based on changes in
the fair value of energy trading contracts.
<PAGE>
           Recording the net change in the fair value of open trading  contracts
as revenues prior to settlement is commonly referred to as mark-to-market  (MTM)
accounting.  Under MTM  accounting  the  change in the  unrealized  gain or loss
throughout a contract's term is recognized in each accounting  period.  When the
contract actually settles,  that is, the energy is actually  delivered in a sale
or received in a purchase or the parties  agree to forego  delivery  and receipt
and net settle in cash, the unrealized  gain or loss is reversed out of revenues
and the actual  realized  cash gain or loss is recognized in revenues for a sale
or in  purchased  power  expense  for a  purchase.  Therefore,  over the trading
contract's  term an  unrealized  gain or loss is  recognized  as the  contract's
market  value  changes.  When the  contract  settles  the total  gain or loss is
realized in cash but only the difference between the accumulated  unrealized net
gains or losses  recorded in prior months and the cash  proceeds is  recognized.
Unrealized  mark-to-market gains and losses are included in the Balance Sheet as
energy trading contract assets or liabilities.
        Our trading activities represent physical forward electricity  contracts
that are typically settled by entering into offsetting contracts.  An example of
our  trading  activities  is when,  in  January,  we enter into a forward  sales
contract  to deliver  electricity  in July.  At the end of each month  until the
contract  settles in July, we would record any  difference  between the contract
price and the market price as an  unrealized  gain or loss in revenues.  In July
when the contract  settles,  we would realize a gain or loss in cash and reverse
to revenues the previously recorded cumulative unrealized gain or loss. Prior to
settlement,  the change in the fair value of physical  forward sale and purchase
contracts is included in revenues on a net basis.  Upon  settlement of a forward
trading  contract,  the amount  realized is  included  in  revenues  for a sales
contract and realized cost is included in purchased power expense for a purchase
contract with the prior change in unrealized fair value reversed in revenues.
        Continuing  with the above  example,  assume  that  later in  January or
sometime in February  through July we enter into an offsetting  forward contract
to buy  electricity  in July. If we do nothing else with these  contracts  until
settlement in July and if the volumes,  delivery  point,  schedule and other key
terms match,  then the difference  between the sale price and the purchase price
represents a fixed value to be realized  when the  contracts  settle in July. If
the purchase  contract is perfectly  matched  with the sales  contract,  we have
effectively fixed the profit or loss;  specifically it is the difference between
the contracted settlement price of the two contracts.  Mark-to-market accounting
for these  contracts  from this point  forward  will have no  further  impact on
results of operations  but will have an  offsetting  and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase  contract prior to entering into a sales contract.  If
the sale and  purchase  contracts do not match  exactly as to volumes,  delivery
point,   schedule  and  other  key  terms,   then  there  could  be   continuing
mark-to-market  effects on revenues from  recording  additional  changes in fair
values using mark-to-market accounting.
        The  fair  value  of open  short-term  trading  contracts  are  based on
exchange  prices and broker quotes.  We  mark-to-market  open long-term  trading
contracts based mainly on AEP-developed  valuation models. These models estimate
future energy  prices based on existing  market and broker quotes and supply and
demand market data and  assumptions.  The fair values  determined are reduced by
<PAGE>
reserves to adjust for credit risk and liquidity  risk.  Credit risk is the risk
that the  counterparty  to the  contract  will  fail to  perform  or fail to pay
amounts due AEP.  Liquidity risk represents the risk that  imperfections  in the
market  will cause the price to be less than or more than what the price  should
be based purely on supply and demand.  There are inherent  risks  related to the
underlying  assumptions  in models  used to fair  value open  long-term  trading
contracts.  AEP has independent  controls to evaluate the  reasonableness of our
valuation models. However,  energy markets,  especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ  from  actual  prices  throughout  a  contract's  term and when
contracts  settle.  Therefore,  there could be significant  adverse or favorable
effects on future  results  of  operations  and cash  flows if market  prices at
settlement do not correlate with the AEP-developed price models.
        Volatility in commodities  markets affects the fair values of all of our
open trading  contracts  exposing SWEPCo to market risk. See  "Quantitative  and
Qualitative  Disclosures  about  Market Risk"  section for a  discussion  of the
policies and procedures used to manage exposure to risk from trading activities.

Results of Operations
        Net income  increased  slightly in the second  quarter and decreased $11
million or 30%,  for the first half of 2002.  The decrease for the first half of
2002  resulted  from  reduced  wholesale  prices and margins due to a decline in
demand for  electricity  which  resulted  from mild weather and a slow  economic
recovery.
        Operating  revenues  decreased 19% in the second quarter and 20% for the
year-to-date period due to decreased wholesale marketing and trading prices. The
changes in the components of revenues were as follows:
<TABLE>
<CAPTION>
                                                                Increase (Decrease)
                                            Second Quarter                              Year-to-Date
                                   (in millions)            %                (in millions)                %
                                                            -                                             -
<S>                                      <C>              <C>                     <C>                   <C>
       Electricity Marketing
        and Trading*                     $(74.7)          (23)                    $(153.3)              (24)
       Energy Delivery*                    (2.0)           (2)                      (11.1)               (7)
       Sales to AEP Affiliates             (4.5)          (24)                      (10.2)              (22)
                                         ------                                   -------
            Total                        $(81.2)          (19)                    $(174.6)              (20)
                                         ======                                   =======
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.

       All of the  components  of  revenues  decreased  in 2002 as a result of
reduced  wholesale  prices due to reduced  energy  demand as a result  of a
decrease  in  marketing  and  trading activity, and the slow economic recovery.
<PAGE>
       Operating  expenses  decreased 20% in the second  quarter and the
year-to-date  period due to a significant decrease in electricity marketing and
trading purchases and fuel expense.
<TABLE>
<CAPTION>
                                                                 Increase (Decrease)
                                                                 -------------------
                                             Second Quarter                         Year-to-Date
                                         (in millions)          %           (in millions)              %
                                                                -                                      -
<S>                                            <C>            <C>                <C>                 <C>
       Fuel                                    $(28.9)        (23)               $ (58.3)            (24)
       Electricity Marketing
        and Trading Purchases                   (60.3)        (38)                (104.0)            (33)
       Purchases from AEP Affiliates               -            -                   (5.6)            (21)
       Other Operation                           10.7          31                   13.5              18
       Maintenance                                0.5           3                   (2.9)             (8)
       Depreciation and Amortization             (2.8)         (8)                  (0.7)             (1)
       Taxes Other Than Income Taxes             (0.6)         (4)                   0.8               3
       Income Taxes                               1.3          16                   (4.8)            (29)
                                               ------                            -------
            Total                              $(80.1)        (20)               $(162.0)            (20)
                                               ======                            =======
</TABLE>
        Fuel expense  decreased due to lower natural gas prices as a result of a
mild winter and the slow economic recovery.
        Decreasing  purchased power prices resulted in decreases to both
electricity  marketing and trading purchases and electricity purchases from AEP
affiliates for the second quarter and first half of 2002. The first half of 2002
was also affected by milder than normal winter.
        The  acquisition  of Dolet Hills  mining  operation  in June 2001 caused
other  operation  expense  to  increase  in  2002.
        Maintenance  expense decreased for the first half of 2002 as a result of
costs  incurred last year to restore service and make repairs following a severe
ice storm.
        The decrease in depreciation and amortization  expense was due primarily
to a  decrease  in  excess  earnings  accruals  under  the  Texas  restructuring
legislation  offset by new  expenses  from the  acquisition  of the Dolet  Hills
mining operation.
        The  increase  in  income  taxes  for  the  second  quarter  of  2002 is
predominately  due to the reversal of deferred  taxes in excess of the statutory
tax rate,  and an increase  in pre-tax  income.  Income  taxes  attributable  to
operations decreased for the first half of 2002 due to a significant decrease in
pre-tax income.
        Nonoperating  income  decreased for the first half of 2002 due primarily
to a reduction in interest income earned on under-recovered  fuel which resulted
from  significant  natural  gas price  increases  in the second half of 2000 and
2001.  During 2001 gas price  declines  and a PUCT  approved  fuel rate and fuel
surcharge  increases lowered the unrecovered fuel balance thus lowering interest
income.
<PAGE>
<TABLE>
<CAPTION>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                               Three Months Ended June 30,               Six Months Ended June 30,
                                                  2002                2001                 2002               2001
                                                  ----                ----                 ----               ----
                                                                         (in thousands)
<S>                                            <C>                  <C>                 <C>                <C>
OPERATING REVENUES:
  Electricity Marketing and Trading            $255,385             $330,094            $495,730           $649,080
  Energy Delivery                                84,008               85,970             152,943            164,027
  Sales to AEP Affiliates                        14,224               18,731              37,184             47,377
                                               --------             --------            --------           --------
           TOTAL OPERATING REVENUES             353,617              434,795             685,857            860,484
                                               --------             --------            --------           --------

OPERATING EXPENSES:
   Fuel                                          95,207              124,151             184,090            242,397
   Purchased Power:
     Electricity Marketing and Trading           96,349              156,608             207,444            311,403
     AEP Affiliates                              12,075               12,063              20,516             26,125
   Other Operation                               44,725               34,071              86,876             73,339
   Maintenance                                   20,942               20,431              32,780             35,667
   Depreciation and Amortization                 30,533               33,328              60,673             61,458
   Taxes Other Than Income Taxes                 12,889               13,485              27,355             26,513
   Income Taxes                                   9,317                8,009              12,074             16,947
                                               --------             --------            --------           --------
          TOTAL OPERATING EXPENSES              322,037              402,146             631,808            793,849
                                               --------             --------            --------           --------

OPERATING INCOME                                 31,580               32,649              54,049             66,635

NONOPERATING INCOME                                 313                  850                 415              1,683
NONOPERATING EXPENSES (CREDITS)                     (20)                 681                 546              1,320
NONOPERATING INCOME TAX EXPENSE
 (CREDIT)                                          (137)                 139                (109)                86

INTEREST CHARGES                                 13,895               14,895              27,713             29,259
                                               --------             --------            --------           --------

NET INCOME                                       18,155               17,784              26,314             37,653
                                               --------             --------            --------           --------

PREFERRED STOCK DIVIDEND REQUIREMENTS                58                   58                 115                115
                                               --------             --------            --------           --------

EARNINGS APPLICABLE TO COMMON STOCK            $ 18,097             $ 17,726            $ 26,199           $ 37,538
                                               ========             ========            ========           ========
</TABLE>
<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                    Three Months Ended June 30,              Six Months Ended June 30,
                                      2002                2001                2002                2001
                                      ----                ----                ----                ----
                                                           (in thousands)
<S>                                 <C>                  <C>                <C>                <C>
NET INCOME                          $18,155              $17,784            $26,314            $37,653

OTHER COMPREHENSIVE INCOME
    Cash Flow Power Hedge               230                 -                   230               -
                                    -------              -------            -------            -------

COMPREHENSIVE INCOME                $18,385              $17,784            $26,544            $37,653
                                    =======              =======            =======            =======
</TABLE>
The  common  stock of  SWEPCo  is wholly  owned by AEP.  See Notes to  Financial
Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                         Three Months Ended June 30,             Six Months Ended June 30,
                                           2002                2001                2002               2001
                                           ----                ----                ----               ----
                                                                              (in thousands)
<S>                                     <C>                  <C>                  <C>              <C>
BALANCE AT BEGINNING OF PERIOD          $298,053             $295,248             $308,915         $293,989
NET INCOME                                18,155               17,784               26,314           37,653
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                          18,963               18,552               37,927           37,105
    Preferred Stock                           58                   58                  115              115
                                        --------             --------             --------         --------

BALANCE AT END OF PERIOD                $297,187             $294,422             $297,187         $294,422
                                        ========             ========             ========         ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                    June 30, 2002        December 31, 2001
                                                    -------------        -----------------
                                                                 (in thousands)
<S>                                                      <C>                     <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                            $1,443,282              $1,429,356
   Transmission                                             565,230                 538,749
   Distribution                                           1,036,036               1,042,523
   General                                                  394,628                 376,016
   Construction Work in Progress                             51,488                  74,120
                                                         ----------              ----------
        Total Electric Utility Plant                      3,490,664               3,460,764
   Accumulated Depreciation and Amortization              1,606,606               1,550,618
                                                         ----------              ----------
        NET ELECTRIC UTILITY PLANT                        1,884,058               1,910,146
                                                         ----------              ----------

OTHER PROPERTY AND INVESTMENTS                               44,127                  43,000
                                                         ----------              ----------

LONG-TERM ENERGY TRADING CONTRACTS                           25,267                  63,372
                                                         ----------              ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                 15,860                   5,415
   Accounts Receivable:
      Customers                                              51,533                  44,588
      Affiliated Companies                                   60,171                  12,069
      Allowance for Uncollectible Accounts                     (111)                    (89)
   Fuel Inventory - at average cost                          78,335                  52,212
   Under-recovered Fuel                                        -                      2,501
   Materials and Supplies - at average cost                  36,932                  32,527
   Energy Trading Contracts                                  47,535                 186,159
   Prepayments                                               18,993                  18,716
                                                         ----------              ----------
          TOTAL CURRENT ASSETS                              309,248                 354,098
                                                         ----------              ----------

REGULATORY ASSETS                                            48,165                  51,989
                                                         ----------              ----------

DEFERRED CHARGES                                             79,693                  67,753
                                                         ----------              ----------

          TOTAL ASSETS                                   $2,390,558              $2,490,358
                                                         ==========              ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                       June 30, 2002        December 31, 2001
                                                       -------------        -----------------
                                                                    (in thousands)
<S>                                                        <C>                      <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - $18 Par Value:
      Authorized - 7,600,000 Shares
      Outstanding - 7,536,640 Shares                       $  135,660               $  135,660
   Paid-in Capital                                            245,000                  245,000
   Accumulated Other Comprehensive Income                         230                     -
   Retained Earnings                                          297,187                  308,915
                                                           ----------               ----------
        Total Common Shareowner's Equity                      678,077                  689,575

Preferred Stock                                                 4,704                    4,704
SWEPCO-Obligated, Mandatorily Redeemable Preferred
  Securities of Subsidiary Trust Holding Solely
  Junior Subordinated Debentures of SWEPCO                    110,000                  110,000
Long-term Debt                                                637,810                  494,688
                                                           ----------               ----------

        TOTAL CAPITALIZATION                                1,430,591                1,298,967
                                                           ----------               ----------

OTHER NONCURRENT LIABILITIES                                   14,617                   34,997
                                                           ----------               ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                          55,595                  150,595
   Advances from Affiliates                                    65,073                  117,367
   Accounts Payable - General                                  89,147                   71,810
   Accounts Payable - Affiliated Companies                     94,789                   37,469
   Customer Deposits                                           19,446                   19,880
   Taxes Accrued                                               61,162                   36,522
   Interest Accrued                                            11,473                   13,631
   Energy Trading Contracts                                    54,187                  192,318
   Over-recovered Fuel                                          9,146                     -
   Other                                                       16,275                   26,166
                                                           ----------               ----------

        TOTAL CURRENT LIABILITIES                             476,293                  665,758
                                                           ----------               ----------

DEFERRED INCOME TAXES                                         361,712                  369,781
                                                           ----------               ----------

DEFERRED INVESTMENT TAX CREDITS                                46,452                   48,714
                                                           ----------               ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                    37,754                   17,828
                                                           ----------               ----------

LONG-TERM ENERGY TRADING CONTRACTS                             23,139                   54,313
                                                           ----------               ----------

CONTINGENCIES (Note 8)

        TOTAL CAPITALIZATION AND LIABILITIES               $2,390,558               $2,490,358
                                                           ==========               ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                              Six Months Ended June 30,
                                                                            2002                      2001
                                                                            ----                      ----
                                                                                (in thousands)
<S>                                                                     <C>                       <C>
OPERATING ACTIVITIES:
   Net Income                                                           $  26,314                 $  37,653
   Adjustments for Noncash Items:
      Depreciation and Amortization                                        60,673                    61,458
      Deferred Income Taxes                                                (9,004)                   (4,546)
      Deferred Investment Tax Credits                                      (2,262)                   (2,212)
      Mark-to-Market Energy Trading Contracts                               7,834                    (7,942)
      Deferred Property Taxes                                             (17,545)                  (17,703)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                           (55,025)                    2,286
      Fuel, Materials and Supplies                                        (30,528)                   (4,266)
      Accounts Payable                                                     74,657                   (45,226)
      Taxes Accrued                                                        24,640                    41,158
      Fuel Recovery                                                        11,647                    (9,447)
   Change in Other Assets                                                  10,995                   (47,147)
   Change in Other Liabilities                                            (13,802)                   49,536
                                                                        ---------                 ---------
           Net Cash Flows From Operating Activities                        88,594                    53,602
                                                                        ---------                 ---------

INVESTING ACTIVITIES:
      Construction Expenditures                                           (35,695)                  (49,418)
      Purchase of Dolet Hills                                                -                      (85,716)
      Other                                                                  (284)                     (411)
                                                                        ---------                 ---------
           Net Cash Flows Used For Investing Activities                   (35,979)                 (135,545)
                                                                        ---------                 ---------

FINANCING ACTIVITIES:
      Issuance of Long-term Debt                                          198,616                      -
      Retirement of Long-term Debt                                       (150,450)                     (450)
      Change in Advances from Affiliates (net)                            (52,294)                  119,660
      Dividends Paid on Common Stock                                      (37,927)                  (37,105)
      Dividends Paid on Cumulative Preferred Stock                           (115)                     (115)
                                                                        ---------                 ---------
           Net Cash Flows From (Used For) Financing Activities            (42,170)                   81,990
                                                                        ---------                 ---------

Net Increase in Cash and Cash Equivalents                                  10,445                        47
Cash and Cash Equivalents at Beginning of Period                            5,415                     1,907
                                                                        ---------                 ---------
Cash and Cash Equivalents at End of Period                              $  15,860                 $   1,954
                                                                        =========                 =========
</TABLE>
Supplemental Disclosure:
Cash  paid  for  interest  net  of  capitalized   amounts  was  $21,331,000  and
$25,743,000  and for income taxes was  $24,479,000  and  $4,144,000  in 2002 and
2001, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
                          WEST TEXAS UTILITIES COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2002 vs. SECOND QUARTER 2001
                                       AND
                     YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001

         WTU is a public  utility  engaged in the  generation,  purchase,  sale,
transmission  and  distribution of electric power in west and central Texas. WTU
sells  electric  power at wholesale to other  utilities,  municipalities,  rural
electric  cooperatives and beginning in 2002 to retail electric providers (REPs)
in Texas (see "Introduction of Customer Choice" section below).
         Wholesale power marketing and trading activities are conducted on WTU's
behalf by AEPSC. WTU, along with the other AEP electric operating  subsidiaries,
shares in AEP's forward trades with other utility systems and power marketers.

Introduction of Customer Choice
        On January 1, 2002, customer choice of electricity supplier began in the
Electric  Reliability  Council of Texas  (ERCOT)  area of Texas.  WTU  currently
operates in both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with
the majority of its operations being in the ERCOT territory.
        Under the Texas  Restructuring  Legislation,  each electric  utility has
been  required to submit a plan to  structurally  unbundle its  business  into a
retail electric provider, a power generator, and a transmission and distribution
utility.  During the year 2000,  WTU  submitted a plan for  separation  that was
subsequently  approved  by the PUCT.  As a result of this  legislation,  WTU has
functionally  separated its generation from its  transmission  and  distribution
operations  and formed a separate REP.  Pending  regulatory  approval,  WTU will
corporately  separate its  generation  from its  transmission  and  distribution
operations.  The REP is a separate  legal entity that is a subsidiary of AEP and
is not  owned by or  consolidated  with WTU.  Since  the REP is the  electricity
supplier to retail  customers in the ERCOT area, WTU sells its generation to the
REP and provides  transmission and distribution  services to retail customers in
its ERCOT  service  territory.  As a result of the  formation of the REP, WTU no
longer supplies  electricity to retail customers in the ERCOT area.  Instead WTU
sells its  generation to the REP that was unbundled  from WTU and also sells its
generation to other REPs in the area. The implementation of REPs as suppliers to
retail  customers  has caused a  significant  shift in WTU's sales as  described
below under "Results of Operations."

Critical Accounting Policies - Revenue Recognition
Regulatory   Accounting  -  As  a  result  of  our   cost-based   rate-regulated
transmission and distribution  operations,  our financial statements reflect the
actions  of  regulators  that can  result in the  recognition  of  revenues  and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities  (future revenue  reductions or refunds) are recorded to reflect the
economic effects of regulation by matching  expenses with their recovery through
regulated revenues in the same accounting period.


<PAGE>


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

Traditional  Electricity Supply and Delivery  Activities - We recognize revenues
on an accrual basis for electricity  supply sales and  electricity  transmission
and distribution  delivery  services.  The revenues are recognized in our income
statement  when the energy is delivered to the customer and include  unbilled as
well as billed amounts. In general, expenses are recorded when incurred.

Energy Marketing and Trading  Activities - AEP engages in wholesale  electricity
marketing  and  trading  transactions  (trading  activities).  A portion  of the
revenues and costs of AEP's trading  activities  are  allocated to WTU.  Trading
activities  allocated  to WTU  involve  the  purchase  and sale of energy  under
physical  forward  contracts  at fixed and  variable  prices.  Although  trading
contracts are generally short-term,  there are also long-term trading contracts.
We recognize revenues from trading activities  generally based on changes in the
fair value of open energy trading contracts.
           Recording the net change in the fair value of open trading  contracts
as revenues prior to settlement is commonly referred to as mark-to-market  (MTM)
accounting.  Under MTM  accounting  the  change in the  unrealized  gain or loss
throughout a contract's term is recognized in each accounting  period.  When the
contract actually settles,  that is, the energy is actually  delivered in a sale
or received in a purchase or the parties agree to forego delivery and receipt of
electricity  and net settle in cash, the unrealized  cumulative  gain or loss is
reversed out of revenues and the actual realized cash gain or loss is recognized
in revenues for a sale or in purchased power expense for a purchase.  Therefore,
over the trading contract's term an unrealized gain or loss is recognized as the
contract's  market value  changes.  When the contract  settles the total gain or
loss is  realized  in cash but  only  the  difference  between  the  accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized.  Unrealized  mark-to-market  gains and  losses are  included  in the
balance sheet as energy trading contract assets or liabilities.
        Our trading activities represent physical forward electricity  contracts
that are typically settled by entering into offsetting contracts.  An example of
our  trading  activities  is when,  in  January,  we enter into a forward  sales
contract  to deliver  electricity  in July.  At the end of each month  until the
contract  settles in July, we would record our share of any  difference  between
the  contract  price  and the  market  price  as an  unrealized  gain or loss in
revenues.  In July when the contract  settles,  we would  realize our share of a
gain or loss in cash and reverse to revenues the previously  recorded cumulative
unrealized  gain or loss.  Prior to settlement,  the change in the fair value of
physical  forward sale and  purchase  contracts is included in revenues on a net
basis.  Upon  settlement of a forward trading  contract,  the amount realized is
included in revenues for a sales  contract and the realized  cost is included in
purchased  power  expense  for a  purchase  contract  with the  prior  change in
unrealized fair value reversed in revenues.

<PAGE>

        Continuing  with the above  example,  assume  that  later in  January or
sometime in February  through July we enter into an offsetting  forward contract
to buy  electricity  in July. If we do nothing else with these  contracts  until
settlement in July and if the volumes,  delivery  point,  schedule and other key
terms match,  then the difference  between the sale price and the purchase price
represents a fixed value to be realized  when the  contracts  settle in July. If
the purchase  contract is perfectly  matched  with the sales  contract,  we have
effectively fixed the profit or loss;  specifically it is the difference between
the contracted settlement price of the two contracts.  Mark-to-market accounting
for these  contracts  from this point  forward  will have no  further  impact on
results of operations  but will have an  offsetting  and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase  contract prior to entering into a sales contract.  If
the sale and  purchase  contracts do not match  exactly as to volumes,  delivery
point,   schedule  and  other  key  terms,   then  there  could  be   continuing
mark-to-market  effects on revenues from  recording  additional  changes in fair
values using mark-to-market accounting.
        The  fair  value  of open  short-term  trading  contracts  are  based on
exchange  prices and broker quotes.  We  mark-to-market  open long-term  trading
contracts based mainly on AEP-developed  valuation models. These models estimate
future energy  prices based on existing  market and broker quotes and supply and
demand market data and  assumptions.  The fair values  determined are reduced by
reserves to adjust for credit risk and liquidity  risk.  Credit risk is the risk
that the  counterparty  to the  contract  will  fail to  perform  or fail to pay
amounts due AEP.  Liquidity risk represents the risk that  imperfections  in the
market  will cause the price to be less than or more than what the price  should
be based purely on supply and demand.  There are inherent  risks  related to the
underlying  assumptions  in models  used to fair  value open  long-term  trading
contracts.  AEP has independent  controls to evaluate the  reasonableness of our
valuation models. However,  energy markets,  especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ  from  actual  prices  throughout  a  contract's  term and when
contracts  settle.  Therefore,  there could be significant  adverse or favorable
effects on future  results  of  operations  and cash  flows if market  prices at
settlement do not correlate with the AEP-developed price models.
        Volatility in commodities  markets affects the fair values of all of our
open trading  contracts  exposing WTU to market risk. See the  "Quantitative and
Qualitative  Disclosures  about  Market  Risk"  section  of Part I, Item 2 for a
discussion of the policies and procedures  used to manage  exposure to risk from
trading activities.

Results of Operations
        Net  income  decreased  $5.5  million  or 89% for the  quarter  and $2.4
million or 34% for the year-to-date period. The decreases are primarily due to a
downturn in the overall economy, a significant  decline in wholesale prices, and
the diversion of retail sales from the ultimate  retail  customer to the REPs in
the ERCOT region as of January 1, 2002.
<PAGE>
        Overall operating  revenues  decreased $50.8 million for the quarter and
$104.6 million year-to-date as shown below:
<TABLE>
<CAPTION>
                                                            Increase (Decrease)
                                             Second Quarter                              Year-to-Date
                                  (in millions)            %                (in millions)                 %
                                                           -                                              -
<S>                                       <C>            <C>                       <C>                  <C>
       Electricity Marketing
        and Trading*                      $(92)          (63)                      $(192)               (65)
       Energy Delivery*                     (4)          (10)                         (2)                (3)
       Sales to AEP Affiliates              45           N.M.                         89                N.M.
                                          ----                                     -----
            Total                         $(51)          (26)                      $(105)               (27)
                                          ====                                     =====
</TABLE>
       *Reflects  the  allocation  of  certain   transmission  and  distribution
revenues included in bundled retail rates to energy delivery.

       N.M. = Not Meaningful


       Electricity   marketing  and  trading   revenues   decreased
primarily  as a result of the  elimination  of retail  electricity  sales in the
ERCOT  region as of January 1, 2002.  Also  contributing  to the  decrease was a
decline in prices for power trading  transactions.  In 2002 the wholesale energy
sector has been under pressure from lower  commodity  prices in contrast to last
year when we had strong performance from the wholesale business due to favorable
market conditions.  Sales to AEP affiliates increased primarily due to increased
revenues to the  newly-created  affiliated REP. Although WTU sold electricity to
the affiliated REP instead of directly to retail  customers in the ERCOT region,
total revenues received were lower because of the lower wholesale prices.
       Operating  expenses declined $43.7 million for the quarter and $103.3
million  year-to-date,  primarily due to decreases in fuel expense and purchased
power.  Changes in the components of operating expenses are shown below:
<TABLE>
<CAPTION>
                                                                 Increase (Decrease)
                                                 Second Quarter                          Year-to-Date
                                        (in millions)            %         (in millions)                 %
                                                                 -                                       -
<S>                                             <C>           <C>                 <C>                  <C>
       Fuel                                     $(14)          (30)               $ (49)               (46)
       Electricity Marketing and
        Trading Purchases                        (19)          (29)                 (36)               (29)
       Purchases from AEP Affiliates              (6)          (37)                 (15)               (40)
       Other Operation                            -             -                    (2)                (4)
       Maintenance                                -             -                    -                  -
       Depreciation and Amortization              (1)           (4)                  (1)                (3)
       Taxes Other Than Income Taxes              (1)           (9)                  -                  -
       Income Taxes                               (3)         (116)                  -                  -
                                                ----                              -----
            Total                               $(44)          (24)               $(103)               (28)
                                                ====                              =====
</TABLE>
        Fuel expense decreased  significantly primarily due to a decrease in the
average unit cost of fuel as a result of lower spot market natural gas prices.
        The decline in  electricity  marketing and trading  purchases was mainly
due to reduced prices caused by decreased  electricity  demand driven largely by
the downturn in the economy.
        The  quarter-to-date  decrease in income taxes is predominately due to a
decrease in pre-tax income.
        Nonoperating  income  and  expense  increased  significantly  during the
quarter  and  year-to-date  as a result of  increased  non-utility  revenue  and
expenses associated with energy related construction projects for third parties.
<PAGE>
<TABLE>
<CAPTION>
                          WEST TEXAS UTILITIES COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                        Three Months Ended June 30,              Six Months Ended June 30,
                                            2002               2001                2002               2001
                                            ----               ----                ----               ----
                                                                    (in thousands)
<S>                                       <C>                <C>                 <C>               <C>
OPERATING REVENUES:
  Electricity Marketing and Trading       $ 53,681           $145,720            $104,046          $296,061
  Energy Delivery                           38,550             42,688              79,179            81,330
  Sales to AEP Affiliates                   49,798              4,431             100,040            10,454
                                          --------           --------            --------          --------
         Total Operating Revenues          142,029            192,839             283,265           387,845

OPERATING EXPENSES:
   Fuel                                     32,842             46,848              57,822           106,753
   Purchased Power:
   Electricity Marketing and Trading        44,989             63,650              89,112           124,950
   AEP Affiliates                           10,559             16,835              22,209            37,227
 Other Operation                            24,910             25,355              49,080            51,111
 Maintenance                                 7,050              7,046              11,406            11,608
 Depreciation and Amortization              11,072             11,529              22,641            23,300
 Taxes Other Than Income Taxes               5,726              6,260              12,026            12,298
 Income Taxes (Credit)                        (468)             2,888               2,475             2,778
                                          --------           --------            --------          --------
       Total Operating Expenses            136,680            180,411             266,771           370,025

OPERATING INCOME                             5,349             12,428              16,494            17,820

NONOPERATING INCOME                          6,980                253               5,492             2,298

NONOPERATING EXPENSES                        5,688                188               7,060               520

NONOPERATING INCOME TAX EXPENSE
  (CREDIT)                                     358                618                (631)              900

INTEREST CHARGES                             5,608              5,742              10,890            11,674
                                          --------           --------            --------          --------
NET INCOME                                     675              6,133               4,667             7,024
PREFERRED STOCK DIVIDEND REQUIREMENTS           26                 26                  52                52
                                          --------           --------            --------          --------

EARNINGS APPLICABLE TO COMMON STOCK       $    649           $  6,107            $  4,615          $  6,972
                                          ========           ========            ========          ========
</TABLE>
<TABLE>
<CAPTION>
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                   Three Months Ended June 30,                 Six Months Ended June 30,
                                  2002                     2001                  2002              2001
                                  ----                     ----                  ----              ----
                                                              (in thousands)

<S>                               <C>                     <C>                   <C>              <C>
NET INCOME                        $675                    $6,133                $4,667           $7,024

OTHER COMPREHENSIVE INCOME
    Cash Flow Power Hedge           78                      -                       78             -
                                  ----                    ------                ------           ------

COMPREHENSIVE INCOME              $753                    $6,133                $4,745           $7,024
                                  ====                    ======                ======           ======
</TABLE>
The common  stock of the Company is wholly  owned by AEP. See Notes to Financial
Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                          WEST TEXAS UTILITIES COMPANY
                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                       Three Months Ended June 30,              Six Months Ended June 30,
                                          2002                2001                2002               2001
                                          ----                ----                ----               ----
                                                                           (in thousands)
<S>                                     <C>                <C>                 <C>               <C>
BALANCE AT BEGINNING OF PERIOD          $103,187           $116,247            $105,970          $122,588
NET INCOME                                   675              6,133               4,667             7,024

DEDUCTIONS:
  Cash Dividends Declared:
  Common Stock                             6,749              7,206              13,498            14,412
  Preferred Stock                             26                 26                  52                52
                                        --------           --------            --------          --------

BALANCE AT END OF PERIOD                $ 97,087           $115,148            $ 97,087          $115,148
                                        ========           ========            ========          ========
</TABLE>
The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                          WEST TEXAS UTILITIES COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                        June 30, 2002           December 31, 2001
                                                        -------------           -----------------
                                                                 (in thousands)
<S>                                                         <C>                        <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                               $  442,670                 $  443,508
   Transmission                                                254,463                    250,023
   Distribution                                                440,271                    431,969
   General                                                     108,642                    112,797
   Construction Work in Progress                                32,115                     22,575
                                                            ----------                 ----------
        Total Electric Utility Plant                         1,278,161                  1,260,872
   Accumulated Depreciation and Amortization                   557,728                    546,162
                                                            ----------                 ----------
       NET ELECTRIC UTILITY PLANT                              720,433                    714,710
                                                            ----------                 ----------

OTHER PROPERTY AND INVESTMENTS                                  25,329                     24,933
                                                            ----------                 ----------

LONG-TERM ENERGY TRADING CONTRACTS                              12,985                     21,532
                                                            ----------                 ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                                     1,908                      2,454
   Accounts Receivable:
      Customers                                                 29,200                     18,720
      Affiliated Companies                                      72,975                      8,656
      Allowance for Uncollectible Accounts                        (219)                      (196)
   Fuel - at average cost                                       10,038                      8,307
   Materials and Supplies - at average cost                      4,464                     11,190
   Under-recovered Fuel Costs                                   34,842                     32,791
   Energy Trading Contracts                                     25,156                     63,252
   Prepayments and Other Current Assets                          1,655                        966
                                                            ----------                 ----------
          TOTAL CURRENT ASSETS                                 180,019                    146,140
                                                            ----------                 ----------

REGULATORY ASSETS                                               10,392                     13,659
                                                            ----------                 ----------

DEFERRED CHARGES                                                25,717                      2,446
                                                            ----------                 ----------

          TOTAL ASSETS                                      $  974,875                 $  923,420
                                                            ==========                 ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                          WEST TEXAS UTILITIES COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                  June 30, 2002             December 31, 2001
                                                  -------------             -----------------
                                                                (in thousands)
<S>                                                      <C>                          <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common Stock - $25 Par Value:
      Authorized - 7,800,000 Shares
      Outstanding - 5,488,560 Shares                     $137,214                     $137,214
   Paid-in Capital                                          2,236                        2,236
   Accumulated Other Comprehensive Income                      78                         -
   Retained Earnings                                       97,087                      105,970
                                                         --------                     --------
        Total Common Shareowner's Equity                  236,615                      245,420
Cumulative Preferred Stock Not Subject to
  Mandatory Redemption                                      2,482                        2,482
Long-term Debt                                            221,028                      220,967
                                                         --------                     --------

        TOTAL CAPITZALIZATION                             460,125                      468,869
                                                         --------                     --------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                      35,000                       35,000
   Advances from Affiliates                               120,439                       50,448
   Accounts Payable - General                              19,129                       33,782
   Accounts Payable - Affiliated Companies                 64,024                       11,388
   Customer Deposits                                         -                           4,191
   Taxes Accrued                                           18,503                       17,358
   Interest Accrued                                          -                           1,244
   Energy Trading Contracts                                24,759                       65,414
   Other                                                   15,890                       12,001
                                                         --------                     --------

        TOTAL CURRENT LIABILITIES                         297,744                      230,826
                                                         --------                     --------

DEFERRED INCOME TAXES                                     147,088                      145,049
                                                         --------                     --------

DEFERRED INVESTMENT TAX CREDITS                            22,145                       22,781
                                                         --------                     --------

LONG-TERM ENERGY TRADING CONTRACTS                         11,212                       18,455
                                                         --------                     --------

REGULATORY LIABILITIES AND DEFERRED CREDITS                36,561                       37,440
                                                         --------                     --------

CONTINGENCIES (Note 8)

        TOTAL CAPITALIZATION AND LIABILITIES             $974,875                     $923,420
                                                         ========                     ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                          WEST TEXAS UTILITIES COMPANY
                            STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                          Six Months Ended June 30,
                                                                        2002                   2001
                                                                                  (in thousands)
<S>                                                                <C>                     <C>
OPERATING ACTIVITIES:
   Net Income                                                      $   4,667               $   7,024
   Adjustments for Noncash Items:
      Depreciation and Amortization                                   22,641                  23,300
      Deferred Income Taxes                                            1,470                  (4,738)
      Deferred Investment Tax Credits                                   (636)                   (636)
      Mark-to-Market Energy Trading Contracts                         (1,134)                 (2,639)
      Deferred Property Taxes                                         (7,175)                 (6,200)
   Changes in Certain Assets and Liabilities:
      Accounts Receivable (net)                                      (74,776)                 24,941
      Fuel, Materials and Supplies                                     4,995                  (3,276)
      Accounts Payable                                                37,983                 (42,805)
      Taxes Accrued                                                    1,145                  13,305
      Fuel Recovery                                                   (2,051)                  8,978
   Change in Other Assets                                            (16,944)                    730
   Change in Other Liabilities                                        (2,018)                    585
                                                                   ---------               ---------
           Net Cash Flows From (Used For) Operating Activities       (31,833)                 18,569
                                                                   ---------               ---------

INVESTING ACTIVITIES:
      Construction Expenditures                                      (25,154)                (20,312)
      Other                                                             -                       (127)
                                                                   ---------               ---------
           Net Cash Flows Used For Investing Activities              (25,154)                (20,439)
                                                                   ---------               ---------

FINANCING ACTIVITIES:
      Change in Advances from Affiliates (net)                        69,991                  13,375
      Dividends Paid on Common Stock                                 (13,498)                (14,412)
      Dividends Paid on Cumulative Preferred Stock                       (52)                    (52)
                                                                   ---------               ---------
           Net Cash Flows From (Used For) Financing Activities        56,441                  (1,089)
                                                                   ---------               ---------

Net Decrease in Cash and Cash Equivalents                               (546)                 (2,959)
Cash and Cash Equivalents at Beginning of Period                       2,454                   6,941
                                                                   ---------               ---------
Cash and Cash Equivalents at End of Period                         $   1,908               $   3,982
                                                                   =========               =========
</TABLE>
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized  amounts was $9,841,000 and
$10,139,000  and for income taxes was  $2,408,000 and  ($2,957,000)  in 2002 and
2001, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
                          NOTES TO FINANCIAL STATEMENTS
                                  JUNE 30, 2002
                                   (UNAUDITED)

The notes to financial statements are a combined presentation for AEP and its subsidiary registrants as follows:
                Note                                           Registrant that Note applies to
                ----                                           -------------------------------
<S>                                         <C>
1.           General                        AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU

2.           Goodwill and Other
                Intangible Assets           AEP

3.           Acquisitions and
                Dispositions                AEP

4.           Industry Restructuring         AEP, APCo, CPL, CSPCo, I&M, OPCo, SWEPCo, WTU

5.           Rate Matters                   AEP, APCo, CPL, PSO, SWEPCo, WTU

6.           Business Segments              AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU

7.           Financing and Related
                Activities                  AEP, APCo, CPL, I&M, KPCo, OPCo, SWEPCo

8.           Contingencies                  AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
</TABLE>
1.      GENERAL

               The accompanying unaudited financial statements should be read in
        conjunction  with the 2001 Annual  Report as  incorporated  in and filed
        with the Form 10-K.

               Certain prior period financial  statement items were reclassified
        to conform  to current  period  presentation.  Reclassifications  had no
        effect on previously reported net income.

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

2.      GOODWILL AND OTHER INTANGIBLE ASSETS

               SFAS 142,  "Goodwill and Other  Intangible  Assets" was effective
        for AEP on  January 1,  2002.  The  adoption  of SFAS 142  requires  the
        transition testing for impairment of all indefinite lived intangibles by
        the end of the first quarter and initial  testing of goodwill by the end
        of the  second  quarter  of 2002.  In the  first  quarter  of 2002,  AEP
        completed  testing  the  goodwill  of its  domestic  operations  and its
        indefinite lived intangible  assets and there was no impairment.  In the
        second  quarter  of 2002  we  completed  initial  testing  for  goodwill
        impairment  of our UK  and  Australian  retail  electricity  and  supply
        operations. As a result of that testing, we determined that we had a net
        transitional  impairment  loss of $350  million,  which is reported as a
        cumulative effect of an accounting principle change.

               SFAS 142 also changed the  accounting  and reporting for goodwill
        and other intangible assets.  Effective with the adoption of SFAS 142 on
        January 1, 2002 the amortization of goodwill  ceased.  SFAS 142 requires
        that other intangible  assets be separately  identified and if they have
        finite lives, they must be amortized over that life.



<PAGE>


               New  reporting  requirements  imposed  by SFAS  142  include  the
disclosures shown below.

        Goodwill

               The changes in the carrying amount of goodwill for the six months
ended June 30, 2002 by operating segment are:
<TABLE>
<CAPTION>
                                                         Energy
                                      Wholesale          Delivery           Other          AEP Consolidated
                                                                       (in millions)
<S>                                           <C>             <C>              <C>                     <C>
       Balance January 1, 2002                $340            $37              $ 40                    $417
       Goodwill acquired                         2              -                -                        2
       Goodwill assigned from
        purchase price allocation
        for recent prior period
        acquisitions                            94              -                -                       94
       Transitional impairment loss              -              -               (27)                    (27)
       Non-transitional
        impairment loss                          -              -               (12)                    (12)
       Foreign currency exchange
         rate changes                            6              -                 2                       8
                                              ----            ---              ----                    ----
       Balance June 30, 2002                  $442            $37              $  3                    $482
                                              ====            ===              ====                    ====
</TABLE>
               In  the  first  quarter  of  2002,   AEP  recognized  a  goodwill
        impairment  loss of $12  million  ($8 million net of tax) as a result of
        management's  decision to exit its Gas Power  Systems  business that was
        developing  customized generators powered by surplus helicopter engines.
        Management  elected to exit this business due to technical problems with
        the  underlying  technology  and  recognized an impairment  loss for all
        goodwill related to the acquisition of Gas Power Systems.

               The  transitional  impairment loss related to SEEBOARD  goodwill,
        which is reported as a cumulative  effect of an  accounting  change,  is
        excluded from the above  schedule.  Under SFAS 144,  SEEBOARD's  assets,
        including  goodwill,  are reported as available  for sale on one line in
        the  balance  sheet.  See Note 3  related  to the sale of  SEEBOARD  and
        CitiPower.

               As   required  by  SFAS  142  the   following   tables  show  the
        transitional  disclosures to adjust reported net income and earnings per
        share to  exclude  amortization  expense  recognized  in  prior  periods
        related to  goodwill  and  intangible  assets  that are no longer  being
        amortized  and  adjustments  for  changes in  amortization  periods  for
        intangible assets that continue to be amortized.

       Net Income                                     Six Months Ended June 30,
                                                     2002                  2001
                                                     ----                  ----
                                                        (in millions)
       Reported Net Income (Loss)                     $(107)               $498
       Add back: Goodwill amortization                   -                   19
       Add back amortization for intangibles with
        indefinite lives under SFAS 142                  -                    4
                                                      -----                ----
       Adjusted Net Income (Loss)                     $(107)               $521
                                                      =====                ====

       Earnings Per Share (Basic and Dilutive)        Six Months Ended June 30,
                                                     2002                  2001
                                                     ----                  ----
       Reported Earnings (Loss) per Share           $(0.33)               $1.54
       Add back: Goodwill amortization                 -                   0.06
       Add back amortization for intangibles with
        indefinite lives under SFAS 142                -                    -
                                                    ------                -----
       Adjusted Earnings (Loss) per Share           $(0.33)               $1.60
                                                    ======                =====



<PAGE>


       Acquired Intangible Assets

               Acquired  intangible  assets  subject  to  amortization  are  $42
        million at June 30,  2002 and $53  million at  December  31, 2001 net of
        accumulated  amortization.  The gross  carrying  amount and  accumulated
        amortization by major asset class are:
<TABLE>
<CAPTION>
                                              June 30, 2002                               December 31, 2001
                               Gross Carrying           Accumulated          Gross Carrying          Accumulated
                               Amount                   Amortization         Amount                  Amortization
                                              (in millions)                                 (in millions)
<S>                                         <C>                     <C>                  <C>                      <C>
       CitiPower retail
        supply licenses                     $ -                     $-                   $24                      $4
       Dolet Hills advanced
        Royalties                            35                      3                    35                       2
       Unpatented Technology                 10                      -                     -                       -
                                            ---                     --                   ---                      --
       Totals                               $45                     $3                   $59                      $6
                                            ===                     ==                   ===                      ==
</TABLE>
               Amortization  of  intangible  assets was $2  million  for the six
        months ended June 30, 2002. Estimated aggregate  amortization expense is
        $4.5 million for each year 2003 through 2008.

               Acquired  intangible assets no longer subject to amortization are
        comprised of distribution  licenses for CitiPower  operating  franchises
        with a carrying amount of $324 million and $421 million at June 30, 2002
        and  December  31, 2001.  The  reduction  in the carrying  values of the
        CitiPower  retail supply and  distribution  licenses  since December 31,
        2001 results from impairment  charges  recorded in the second quarter of
        2002 and  changes in the  foreign  currency  exchange  rate.  See Note 3
        related to the pending sale of CitiPower.

3.      ACQUISITIONS AND DISPOSITIONS

        Disposition of SEEBOARD

                  On June 18,  2002,  AEP,  through a wholly  owned  subsidiary,
         entered into an agreement,  subject to European Union ("EU")  approval,
         to sell its consolidated  subsidiary  SEEBOARD, a UK electricity supply
         and  distribution  company.  EU approval was received July 25, 2002 and
         the sale was  completed  on July 29, 2002.  AEP received  approximately
         $1.04 billion in cash from the sale,  subject to a working capital true
         up, and the buyer assumed SEEBOARD debt of approximately $1.12 billion,
         resulting in a net impairment  loss of $345 million using June 30, 2002
         exchange  rates.  In accordance with SFAS 144 the results of operations
         of SEEBOARD  have been  classified  as  discontinued  operations in the
         accompanying  financial  statements.  $22 million of the net impairment
         loss  was  recorded  in  the  second   quarter  and  is  classified  as
         discontinued operations. The remaining $323 million of the net loss has
         been classified as a transitional  impairment loss from the adoption of
         SFAS 142 (see Note 2) and has been  reported as a cumulative  effect of
         an accounting change retroactive to January 1, 2002.  Proceeds from the
         sale of SEEBOARD were used to pay down bank  facilities  and short-term
         debt.



<PAGE>


                  The assets and liabilities of SEEBOARD have been aggregated on
         the  balance  sheet as assets  held for sale and  liabilities  held for
         sale. The major classes of SEEBOARD's  assets and liabilities  held for
         sale are:
                                            June 30, 2002    December 31, 2001
                                                       (in millions)
        Assets
         Current Assets                             $  324             $  324
         Plant, Property and Equipment, Net          1,457              1,283
         Goodwill                                      867              1,129
         Other Assets                                  102                 96
                                                    ------             ------
          Total Assets Held For Sale                $2,750             $2,832
                                                    ======             ======

        Liabilities
         Current Liabilities                        $  881             $  752
         Long-term Debt                                739                701
         Deferred Income Taxes                         327                268
         Other Liabilities                               8                 77
                                                    ------             ------
          Total Liabilities Held For Sale           $1,955             $1,798
                                                    ======             ======


         Disposition of CitiPower

                  On July 19,  2002,  AEP,  through  a wholly  owned  subsidiary
         entered into an agreement to sell Citipower,  a retail  electricity and
         gas supply and distribution  subsidiary in Australia.  AEP will receive
         net cash of  approximately  $181  million  and the  buyer  will  assume
         CitiPower  debt of  approximately  $774  million.  The  transaction  is
         subject to a net asset true up and is anticipated to close in the third
         quarter of 2002.  AEP recorded a net  impairment  charge  totaling $125
         million.  $98  million was  recorded in the second  quarter of 2002 and
         relates to an impairment loss on the  distribution  license  intangible
         asset.  The  remaining  $27  million  of net  impairment  loss has been
         classified as a transitional goodwill impairment loss from the adoption
         of SFAS 142 (see Note 2) and has been  recorded as a cumulative  effect
         of an accounting change retroactive to January 1, 2002.

                  Since the transaction occurred after the balance sheet date of
         June 30,  2002,  but before the issuance of the  financial  statements,
         CitiPower's  results of operation were not  classified as  discontinued
         operation in accordance with SFAS 144. CitiPower's results of operation
         will be reclassified  as discontinued  operations in the third quarter.
         Also,  CitiPower's  assets and liabilities  have not been aggregated on
         the  balance  sheet as assets  held for sale and  liabilities  held for
         sale.  This too will occur in the third quarter in accordance with SFAS
         144.

         Acquisition of European Trading

                  In  January  2002 AEP  acquired  for $2 million  the  existing
         trading  operations,  including  34 key staff,  of  Enron's  Norway and
         Sweden-based  energy  trading  businesses.  Results of  operations  are
         included in AEP's  consolidated  income statements from the acquisition
         date.  Based on a preliminary  purchase price  allocation the excess of
         cost over fair value of the net assets  acquired  is  approximately  $2
         million which is recorded as goodwill.  The  allocation of the purchase
         price is subject to revision after  completion of a final  appraisal of
         the fair values of the assets acquired and liabilities assumed.

         REPs Transfer

                  In April 2002 AEP reached a  definitive  agreement to transfer
         two of its  Texas  retail  electric  providers  (REPs) to  Centrica,  a
         provider of retail energy and other consumer  services.  An independent
         appraiser will establish a fair market value for the transaction  after
         mid-June  2002.  If the  appraised  value is outside  the range of $133
         million to $153 million, the transaction need not be completed.

                  AEP will provide Centrica with a power supply contract for the
         two REPs and all back-office  services related to these customers for a
         two-year period following closing.  In addition,  AEP retains the right
         to share in earnings from the two REPs above a threshold amount through
         2006 in the event the Texas retail market develops  increased  earnings
<PAGE>
         opportunities.   AEP  will  also   receive  an   up-front   payment  of
         approximately $39 million from Centrica associated with the back-office
         service agreement. Completion of the transaction is contingent upon the
         fair  market  value   appraisal   meeting  the   required   contractual
         guidelines,  regulatory  approval from the PUCT and federal  anti-trust
         clearance.  AEP and Centrica expect to complete the regulatory approval
         process and conclude the transaction by the end of 2002.

4.      INDUSTRY RESTRUCTURING

                As discussed in the 2001 Annual Report, customer choice began in
        four of the eleven state retail  jurisdictions in which the AEP domestic
        electric utility companies  operate.  The following  paragraphs  discuss
        significant  events  occurring  in 2002  related to customer  choice and
        industry restructuring.

        Ohio Restructuring - Affecting AEP, CSPCo and OPCo

                 As discussed in Note 7 of the Notes to Financial Statements in
        the 2001 Annual  Report,  CSPCo and OPCo  filed an  appeal  with the
        Ohio  Supreme  Court related to a tax expense  issue which would result
        in  duplicate  expense of $40 million and $50 million,  respectively,
        for a twelve month period  beginning on May 1, 2001. On April 3, 2002,
        the Ohio Supreme Court  rejected the  companies' arguments  related to a
        duplicate tax period and affirmed the PUCO's order which established the
        effective date of tax credit riders in rates. This ruling had no impact
        on results of operations as the companies had recorded an  extraordinary
        loss when the prepaid asset was stranded by a PUCO order in 2001.

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

                 The complainants seek, among other relief, an order from  the
        PUCO suspending collection of transition charges by CSPCo and OPCo until
        transfer  of  control  of  their  transmission  assets  has occurred and
        imposing a $25,000 per company  forfeiture  for each  day AEP  fails  to
        comply with its commitment to transfer control of transmission assets to
        an RTO.

                 Due to FERC delays in the  approval of our RTO  filings,  CSPCo
        and OPCo  have  been  unable  to implement their RTO participation plan.
        Management is unable to predict the timing of FERC's  final  approval of
        RTOs and the timing of an RTO being operational  or the  outcome of this
        proceeding before the PUCO.

        Virginia Restructuring - Affecting AEP and APCo

               On January 1, 2002,  choice of  electricity  supplier  for retail
        customers  began in  Virginia.  Presently,  APCo  continues  to  service
        virtually all its previous customers.  Pursuant to settlement agreements
        and terms of the  restructuring  law,  APCo's capped rates are the rates
        which  were in  effect  on July 1,  1999  and no  wires  charge  will be
        collected during 2002.  However,  the Virginia  restructuring law allows
        rates to be adjusted in certain circumstances  including changes in fuel
        prices (see Note 5). See the 2001 Annual  Report for further  discussion
        of Virginia restructuring.

        Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU

                As  discussed  in the 2001  Annual  Report,  on January 1, 2002,
        customer  choice of  electricity  supplier  began in the  ERCOT  area of
        Texas.  Customer  choice  has  been  delayed  in  other  areas  of Texas
        including the SPP area.  All of SWEPCo's  Texas service  territory and a
        small  portion of WTU's  service  territory are located in the SPP area.
        CPL operates entirely in the ERCOT area of Texas.

<PAGE>

                Under  the  Texas   Legislation,   the  PUCT  approved  business
        separation  plans for the utility  companies.  The  business  separation
        plans  provided  for CPL and WTU to  establish  separate  companies  and
        divide  their  integrated  utility  operations  and assets  into a power
        generation company, a transmission and distribution utility and a retail
        electric provider.

                Due to the delay in the start of competition in the SPP area and
        lack of regulatory  approval for our  corporate  separation  plan,  only
        CPL's  and WTU's  retail  electric  providers  commenced  operations  on
        January  1,  2002.   Operations  for  CPL,  SWEPCo  and  WTU  have  been
        functionally  separated.   The  companies  anticipate  completing  legal
        separation following receipt of the appropriate regulatory approvals.

                In February 2002, CPL through a subsidiary,  issued $797 million
        of transition  notes approved under the  securization  provisions in the
        Texas  Restructuring  Legislation.  The  transition  notes  provide more
        economical   financing   for   certain   transition   generation-related
        regulatory assets during their recovery period.

                 A 2004 true-up  proceeding  will  determine the amount of total
        stranded  costs,  if  any,  including  the  final  fuel  recovery,   net
        regulatory  asset recovery,  certain  environmental  costs,  accumulated
        excess earnings offsets and other issues.  The Texas Legislation  allows
        for several  alternative  methods to be used to value  stranded costs in
        the final 2004 true-up proceeding  including the sale of and/or exchange
        of generation  assets, the issuance of power generation company stock to
        the public or the use of an ECOM  model.  To the  extent  that the final
        2004 true-up  proceeding  determines that CPL should recover  additional
        stranded  costs,   the  additional   amount   recoverable  can  also  be
        securitized.

                 Two unaffiliated Texas utilities reached settlement  agreements
        approved by the PUCT regarding  recovery of stranded  generation  costs.
        CPL is not  presently  engaged in any  settlement  discussions  with the
        PUCT. CPL's generation-related  regulatory assets subject to recovery as
        stranded costs are approximately  $1.1 billion of which $949 million has
        been securitized pending the 2004 true-up proceeding's  determination of
        stranded   costs   recovery   including   the   recovery   of   stranded
        generation-related  regulatory  assets.  WTU and  SWEPCo do not have any
        recoverable Texas generation-related regulatory assets.

                 The PUCT  ordered  CPL to  reduce  distribution  rates by $54.8
        million over a five-year  period  beginning  January 1, 2002 in order to
        return  estimated  excess  earnings for 1999,  2000 and 2001.  The Texas
        Restructuring Legislation intended that excess earnings would be used to
        reduce  stranded cost.  Final stranded cost amounts and the treatment of
        excess earnings will be determined in the 2004 true-up  proceeding.  The
        PUCT  currently  estimates  that CPL will have no stranded  cost and has
        ordered  the rate  reduction  to return  excess  earnings,  pending  the
        outcome  of the 2004  true-up  proceeding.  Since  CPL  expensed  excess
        earnings  amounts 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.

                 Beginning  January 1, 2002, fuel costs for CPL and WTU in ERCOT
        are  no  longer  subject  to  PUCT  fuel   reconciliation   proceedings.
        Consequently, CPL and WTU will file a final fuel reconciliation with the
        PUCT  which  reconciles  their  fuel costs  through  the  period  ending
        December 31, 2001. As discussed in Note 5 "Rate Matters",  WTU filed its
        final fuel  reconciliation for its ERCOT service territory with the PUCT
        in June  2002.  These  final  fuel  balances  will be  included  in each
        company's 2004 true-up  proceeding.  The  elimination of the fuel clause
        recoveries in 2002 in Texas will subject AEP, CPL and WTU to the risk of
        fuel  market  price  increases  and could  adversely  affect  results of
        operations.

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



<PAGE>


        Michigan Restructuring - Affecting AEP and I&M

                  Customer  choice  commenced  for I&M's  Michigan  customers on
        January 1, 2002.  Effective  with that date the rates on I&M's  Michigan
        customers'  bills for retail  electric  service were  unbundled to allow
        customers the opportunity to evaluate the cost of generation service for
        comparison  with other  offers.  I&M's total  rates in  Michigan  remain
        unchanged  and  reflect  cost of  service.  At this time,  none of I&M's
        customers  have elected to change  suppliers and no competing  suppliers
        are active in I&M's Michigan service territory.

                  Management  has  concluded  that  as  of  June  30,  2002  the
        requirements  to apply SFAS 71  continue to be met since I&M's rates for
        generation in Michigan continue to be cost-based regulated.  As a result
        I&M has not yet discontinued regulatory accounting under SFAS 71.

        West Virginia Restructuring - Affecting AEP and APCo

                  As  discussed  in Note 7 of the 2001 Annual  Report,  the West
        Virginia Legislature in 2000 approved an electricity restructuring plan.
        Before  implementation of the plan, the West Virginia Legislature needed
        to enact  legislation  to  preserve  the  revenues  of state  and  local
        government.  In the past two legislative sessions,  which usually end in
        March each year,  the West  Virginia  Legislature  has not  enacted  the
        required  legislation.  Due to the lack of activity,  the Public Service
        Commission  of  West  Virginia   closed  two   proceedings   related  to
        electricity restructuring in the summer of 2002.

                  The  two  West  Virginia  Commission  orders  related  to  the
        dismissal of the  respective  dockets  intended  originally to determine
        whether West Virginia should deregulate the generation business,  and to
        develop the Commission's  Deregulation Plan and related Commission rules
        to implement the Plan.

                  Management  is  currently  reviewing  the  impact of these two
         orders  to  determine  if the  West  Virginia  Jurisdiction  meets  the
         conditions to apply SFAS 71.

5.      RATE MATTERS

      Fuel Reconciliation - Affecting AEP and WTU

                  In June 2002 WTU filed with the PUCT to  reconcile  fuel costs
      and to defer any unrecovered portion applicable to retail sales within its
      ERCOT  service area for  inclusion in the 2004  true-up  proceeding.  This
      reconciliation  for the period of July 2000 through  December 2001 will be
      the final fuel  reconciliation  for WTU's ERCOT service  territory.  Texas
      restructuring  legislation  eliminated  fuel  clause  recovery  mechanisms
      beginning  in 2002 for the  ERCOT  area and  provides  for a 2004  true-up
      proceeding to determine  recovery of final fuel balances.  At December 31,
      2001, the under-recovery  balance associated with WTU's ERCOT service area
      was $26.4 million  including  interest.  WTU also  requested  authority to
      surcharge  its SPP  customers.  WTU's SPP  customers  will  continue to be
      subject   to  fuel   reconciliations   until   competition   begins.   The
      under-recovery  balance at December 31, 2001 for WTU's service  within SPP
      was $0.7 million including interest. During the reconciliation period, WTU
      incurred $292.7 million of eligible fuel and fuel related expenses serving
      both ERCOT and SPP retail  customers.  The PUCT is not  expected to act on
      this issue prior to the end of 2002.

      FERC Wholesale Fuel Complaint - Affecting AEP and WTU

                  As discussed in Note 5 of the 2001 Annual Report,  certain WTU
      wholesale  customers  filed a complaint  with FERC  alleging  that WTU had
      overcharged them through the fuel adjustment  clause for certain purchased
      power costs since 1997.  The customers  allege WTU had billed them for not
      only  the  cost  of a  1999  Oklaunion  plant  outage,  but  also  certain
      additional  costs  that are not  permissible  under  the  fuel  adjustment
      clause.

                  Negotiations  to settle the complaint and update the contracts
      are continuing.  In March 2002 WTU recorded a provision for refund of $2.2
      million  before  income taxes.  The actual refund and final  resolution of
      this matter  could  differ  materially  from this  estimate and may have a
      negative  impact on future results of operations,  cash flow and financial
      condition.
<PAGE>
      Texas Retail Price-to-Beat Rates - Affecting AEP

            AEP subsidiaries which are the Texas retail electric providers (REP)
      for the ERCOT area,  CPL REP and WTU REP,  filed with the PUCT in May 2002
      to increase the fuel portion of their  "price-to-beat"  rate in compliance
      with the Texas Restructuring Legislation and rules issued by the PUCT. The
      Texas  legislation  provides for the adjustment of the fuel portion of the
      rate up to twice  annually  based on changes  in the market  price of fuel
      using a natural  gas price  index.  On July 15,  2002,  the PUCT  required
      further  hearings to reconsider  the validity of their  existing rules for
      fuel factor  adjustments.  On July 24,  2002,  CPL REP and WTU REP filed a
      petition with the District Court seeking an injunction commanding the PUCT
      to proceed to a final order based on the  existing  rules and  prohibiting
      the PUCT from conducting a remand proceeding. The District Court issued an
      order on August 9, 2002  requiring  the PUCT to comply  with the  existing
      rules.  CPL REP and WTU REP are unable to predict the response of the PUCT
      to the  Court's  order and when or if they will be able to adjust the fuel
      portion of their "price-to-beat"  rates. A delay or denial of CPL REP's or
      WTU REP's  request to increase the fuel  portion of their  "price-to-beat"
      rates could reduce AEP's future results of operations and cash flows.

      FERC Transmission Rates - Affecting AEP, CPL, PSO, SWEPCo and WTU

            In November 2001 FERC issued an order requiring CPL, PSO, SWEPCo and
      WTU to submit revised open access transmission  tariffs, and calculate and
      issue refunds for  overcharges  from January 1, 1997.  The order  resulted
      from a remand by an  appeals  court of a tariff  compliance  filing  order
      issued in November 1998 that had been appealed by certain  customers.  CPL
      and WTU  recorded  refund  provisions  of $1.7  million and $0.7  million,
      respectively,  including  interest in 2001 for this order.  PSO and SWEPCo
      recorded  $100,000  each in 2001 for this order  making the AEP total $2.6
      million.   On  July  26,  2002,   FERC  approved  a  revised  open  access
      transmission  tariff.  Refunds  are to be  completed  within 30 days.  The
      amount of the refunds are being calculated. Management does not expect the
      refunds to be materially different from the amounts provided in 2001.

      Texas Transmission Cost Recovery - Affecting AEP, CPL and WTU

            On July 15,  2002,  CPL and WTU filed a  petition  to  update  their
      Transmission Cost Recovery Factor (TCRF) as of September 1, 2002. The TCRF
      allows for the pass  through of changes in  wholesale  transmission  costs
      billed to the  distribution  service  providers  by  transmission  service
      providers. CPL and WTU are seeking TCRF increases of $0.8 million and $0.2
      million,  respectively.  The requested  increases  include  amounts for an
      interim  increase  granted by the PUCT for one  unaffiliated  transmission
      service  provider.  The PUCT  has not  ruled on  whether  interim  amounts
      qualify for a TCRF. If the interim amount is  disallowed,  CPL's and WTU's
      increase would be reduced to $0.4 million and $0.1 million, respectively.

      Virginia Fuel Rate Filing - Affecting AEP and APCo

            In July 2002 APCo filed with the Virginia SCC requesting an increase
      in fuel rates effective January 1, 2003. The request would increase annual
      revenues by approximately  $28 million.  A public hearing is scheduled for
      September 23, 2002 related to this filing.

6.      BUSINESS SEGMENTS

                  AEP has three business segments:  Wholesale,  Energy Delivery
         and Other. The business  activities of each of these segments are as
         follows:
<PAGE>
         Wholesale
         o Generation of electricity for sale to retail and wholesale customers,
         o Marketing  and trading of  electricity,  gas and coal.
         o Gas pipeline and storage  services and other energy supply  related
           business
         o Coal mining,  bulk  commodity  barging  operations  and other energy
           supply related businesses

         Energy Delivery
         o Domestic electricity transmission
         o Domestic electricity distribution

         Other
         o Foreign electricity distribution and supply investments
         o Telecommunication services

                  Segment  results of  operations  for the six months ended June
         30,  2002 and 2001 are  shown  below.  These  amounts  include  certain
         estimates and allocations where necessary.

                 We have used Earnings  before  Interest and Income Taxes (EBIT)
        as a measure of segment operating performance. The EBIT measure is total
        operating  revenues net of total operating expenses and other income and
        deductions  from income.  It differs from net income in that it does not
        take into account interest expense or income taxes.  EBIT is believed to
        be a reasonable  gauge of results of operations.  By excluding  interest
        and income taxes,  EBIT does not give  guidance  regarding the demand of
        debt  service or other  interest  requirements,  or tax  liabilities  or
        taxation  rates.  The effects of  interest  expense and taxes on overall
        corporate  performance  can be seen in the  consolidated  statements  of
        income.

               The amounts shown for the three business segments reported by AEP
        include certain estimates and allocations where necessary.
<TABLE>
<CAPTION>
                                                                          Energy    Other        Reconciling
                                                              Wholesale   Delivery  Investments  Adjustments   Consolidated
        June 30, 2002                                                                       (in millions)
<S>                                                             <C>        <C>          <C>        <C>             <C>
        Revenues from:
          External customers                                    $26,002    $1,694       $  246     $  -            $27,942
          Transactions with other operating segments             (1,151)       (5)        (486)     (1,642)
        Segment EBIT                                                477       461         (174)                        764
        Total assets                                             35,544    13,190        2,424                      51,158

        June 30, 2001 Revenues from:
          External customers                                     26,034     1,672          238                      27,944
          Transaction with other operating segments               1,067        10           30      (1,107)         -
        Segment EBIT                                                845       483          142         (71)          1,399
        Total assets                                             29,566    14,379        7,539      (1,257) (a)     50,227

        (a) Reconciling adjustment for Total Assets:
            Eliminate intercompany balances                                                         (1,448)
            Corporate assets                                                                            37
            Other                                                                                      154
                                                                                                   -------
                                                                                                   $(1,257)
                                                                                                   =======
</TABLE>
               All of the registrant subsidiaries except AEGCo have two business
        segments.  The  segment  results  for  each of  these  subsidiaries  are
        reported  in the  table  below.  AEGCo  has  one  segment,  a  wholesale
        generation  business.  AEGCo's  results of  operations  are  reported in
        AEGCo's financial statements.
<PAGE>
<TABLE>
<CAPTION>
                                                    Six Months Ended                            Six Months Ended
                                                      June 30, 2002                               June 30, 2001
                                                    Segment                                      Segment
                                       Revenues     EBIT         Total Assets       Revenues     EBIT          Total Assets
        Wholesale Segment                                     (in thousands)                               (in thousands)
<S>                                     <C>            <C>         <C>               <C>          <C>              <C>
        APCo                            $2,463,966     $111,292    $3,229,545        $3,523,410   $107,415         $3,666,392
        CPL                                591,805       67,406     3,047,642           973,148    133,446          2,935,249
        CSPCo                            1,636,821      116,606     2,249,185         2,015,358    119,544          2,499,506
        I&M                              1,870,602        7,886     3,649,646         2,394,505     86,108          3,994,291
        KPCo                               601,795        8,225       681,177           831,124      4,162            772,669
        OPCo                             2,394,324      192,718     3,473,145         3,061,833    125,565          3,927,606
        PSO                                378,279        5,684       872,625           644,622     12,124            859,240
        SWEPCo                             532,914       26,357     1,171,373           696,457     32,036          1,184,118
        WTU                                204,086        5,088       418,221           306,515      1,335            400,251
</TABLE>
<TABLE>
<CAPTION>
                                                     Segment                                     Segment
                                       Revenues      EBIT        Total Assets       Revenues     EBIT          Total Assets
        Energy Delivery Segment                         (in thousands)                              (in thousands)
<S>                                      <C>           <C>         <C>                <C>          <C>             <C>
        APCo                             $294,470      $108,841    $2,547,817         $300,021     $115,711        $2,892,449
        CPL                               288,955        80,406     2,188,857          278,763       65,612         2,108,135
        CSPCo                             225,610        39,950     1,265,166          219,310       44,065         1,405,972
        I&M                               153,194        72,365     1,647,373          156,907       61,410         1,802,938
        KPCo                               66,514        29,053       659,723           67,164       27,246           748,333
        OPCo                              284,904        42,851     1,936,738          265,009       58,512         2,190,161
        PSO                               122,547        28,639       972,249          109,711       23,187           957,334
        SWEPCo                            152,943        39,635     1,219,185          164,027       51,909         1,232,449
        WTU                                79,179        12,313       556,654           81,330       21,041           532,734
</TABLE>
<TABLE>
<CAPTION>
        Registrant Subsidiaries
        Company Total                  Revenues     EBIT         Total Assets       Revenues     EBIT          Total Assets
                                                        (in thousands)                              (in thousands)
<S>                                     <C>            <C>         <C>               <C>             <C>           <C>
        APCo                            $2,758,436     $220,133    $5,777,362        $3,823,431      $223,126      $6,558,841
        CPL                                880,760      147,812     5,236,499         1,251,911       199,058       5,043,384
        CSPCo                            1,862,431      156,556     3,514,351         2,234,668       163,609       3,905,478
        I&M                              2,023,796       80,251     5,297,019         2,551,412       147,518       5,797,229
        KPCo                               668,309       37,278     1,340,900           898,288        31,408       1,521,002
        OPCo                             2,679,228      235,569     5,409,883         3,326,842       184,077       6,117,767
        PSO                                500,826       34,323     1,844,874           754,333        35,311       1,816,574
        SWEPCo                             685,857       65,992     2,390,558           860,484        83,945       2,416,567
        WTU                                283,265       17,401       974,875           387,845        22,376         932,985
</TABLE>
7.      FINANCING AND RELATED ACTIVITIES

        Equity Units

                 In June 2002,  AEP issued 6.9 million  equity  units at $50 per
        unit ($345 million).  Each equity-linked  security consists of a forward
        purchase  contract and a senior note issued by AEP. The forward purchase
        contracts obligate the holders to purchase from AEP shares of AEP common
        stock on the stock  purchase date of August 16, 2005. The purchase price
        per equity unit is $50. The number of shares to be  purchased  under the
        forward purchase  contract will be determined under a formula based upon
        the average  closing  price of AEP common stock near the stock  purchase
        date. The senior notes have a principal amount of $50 each and mature on
        August 16, 2007.  The senior notes are pledged as  collateral  to secure
        the  purchase  of common  stock under the  forward  purchase  contracts.
        Holders  may  satisfy  their   obligation  under  the  forward  purchase
        contracts by allowing the senior  notes to be  remarketed.  The proceeds
        from  the  remarketing  will be used to  purchase  a  portfolio  of U.S.
        treasury   securities  that  holders  pledge  to  AEP  to  secure  their
        obligations under the forward purchase contracts. Alternatively, holders
        may choose to continue  holding the senior notes and use other resources
        as  consideration  for the purchase of stock under the forward  purchase
        contracts.
<PAGE>
                 AEP will make quarterly  interest  payments on the senior notes
        at the initial  annual  rate of 5.75%.  The  interest  rate can be reset
        through a  remarketing,  which is initially  scheduled for May 2005. AEP
        will pay the purchaser contract  adjustment  payments at the annual rate
        of 3.50% on the forward purchase contracts.

                 The present value of the contract  adjustment payments has been
        recorded as a liability  in equity unit senior  notes offset by a charge
        to paid-in capital.  Interest  payments on the senior notes are reported
        as interest expense and contract adjustment payments are charged against
        the liability. Accretion of the contract adjustment payment liability is
        reported as interest expense.  We apply the treasury stock method to the
        equity units to calculate diluted earnings per share.

         Common Stock

                 In June 2002,  AEP issued 16 million  shares of common stock at
        $40.90 per share through an equity offering and received net proceeds of
        $634  million.  Proceeds  from the sale of equity units and common stock
        were used to pay down  short-term  debt and  establish a cash  liquidity
        reserve fund.

          Issuances and Retirements of Long-term Debt

               In the first  quarter  of 2002,  CPL  Transition  Funding  LLC, a
        subsidiary  of CPL,  issued $797 million of  transition  notes under the
        provisions  of the Texas  Restructuring  Legislation  (See Note 4).  The
        proceeds were used to reduce CPL's debt and retire 4.5 million shares of
        CPL's common stock.

The notes were issued under the following classes:

                   Principal     Interest    Scheduled Final      Final
        Class        Amount        Rate      Payment Date      Maturity Date
        -----      ---------     --------    ---------------   -------------
              (in millions)     (%)

        A-1           129          3.54        2005               2007
        A-2           154          5.01        2008               2010
        A-3           107          5.56        2010               2012
        A-4           215          5.96        2013               2015
        A-5           192          6.25        2016               2017

        Other  issuances and  retirements of long-term debt and other securities
        during the first six months of 2002 were:

                    Type of                   Principal   Interest
        Company       Debt                      Amount      Rate       Due Date
        -------     -------                   ---------   --------     --------
        Issuances                           (in millions)    (%)
        ---------
        APCo       Senior Unsecured Notes      $  450        4.80      2005
        I&M        Installment Purchase Contracts  50        4.90      2025
        KPCo       Senior Unsecured Notes         125        5.50      2007
        SWEPCo     Senior Unsecured Notes         200        4.50      2005
        Non-Registrant
         AEP Subs. Revolving Credit Agreement     143        Variable  2003
        Retirements
        CPL        Senior Unsecured Notes        $150        Variable  2002
        I&M        Installment Purchase Contract   50        Variable  2014
        KPCo       First Mortgage Bonds            15        7.90      2023
        OPCo       First Mortgage Bonds             5        8.80      2022
        SWEPCo     Senior Unsecured Notes         150        Variable  2002
        Non-Registrant
         AEP Subs. Notes Payable                   12        Variable  2002-2007
<PAGE>
        Related Activities

                 AEP Credit renewed its sale of receivables agreement during the
        second  quarter  of 2002.  At June  30,  2002,  the sale of  receivables
        agreement provided  commitments of $600 million to purchase  receivables
        from AEP  Credit,  of which $455  million  was  outstanding.  All of the
        receivables sold,  represented affiliate  receivables.  The commitment's
        new term under the sale of  receivables  agreement  will  remain at $600
        million until May 28, 2003. AEP Credit maintains a retained  interest in
        the receivables  sold and this interest is pledged as collateral for the
        collection  of the  receivables  sold.  The fair  value of the  retained
        interest  is based on book  value  due to the  short-term  nature of the
        accounts  receivables  less an allowance for  anticipated  uncollectible
        accounts.

                 In April 2002, AEP closed on a bridge loan facility  consisting
        of a $1,125 million 364-day revolving credit facility and a $600 million
        364-day  term loan  facility to prepare  for  corporate  separation.  We
        borrowed  $600  million  under the term loan  facility  and  loaned  the
        amounts  borrowed to CPL ($200  million),  CSPCo ($250 million) and OPCo
        ($150  million).  Pricing on the  facilities and  intercompany  loans is
        based on a spread over LIBOR.

                 AEP has  available  $3.5  billion in bank  facilities
        consisting  of a  $2.5  billion  364-day  facility  and a  $1.0  billion
        five-year  facility  maturing  on May 31,  2005.  On May 22,  2002,  AEP
        renewed the $2.5 billion facility for another year extending the
        maturity date to May 21, 2003.

                 Upon the issuance of the $450 million 4.80% unsecured notes due
        in 2005,  APCo  announced the following  debt would be redeemed in July;
        $75  million  of 8.25%  junior  subordinated  debentures  due 2026,  $90
        million of 8% junior  subordinated  debentures  due 2027, $40 million of
        6.65%  first  mortgage  bonds due 2003 and $30  million  of 6.85%  first
        mortgage bonds due 2003.

                 Upon  issuance of the $125 million  5.50%  unsecured  notes due
        2007,  KPCo  announced the  redemption of $45 million of first  mortgage
        bonds on August 1.

                 In   preparation   for  corporate   restructuring,   management
        announced the following  bonds would be redeemed in July,  CSPCo's $72.8
        million  remaining  outstanding  principal  amount of the 8-3/8%  junior
        subordinated  debentures  due 2025 and $40  million of the 7.92%  junior
        subordinated  debentures  due  2027 and  OPCo's  $85  million  remaining
        outstanding  principal of the 8.16% junior  subordinated  debentures due
        2025 and $50 million of the 7.92%  junior  subordinated  debentures  due
        2027.

8.      CONTINGENCIES

        Litigation

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

               As discussed in Note 8 of the Notes to  Financial  Statements  in
        the 2001  Annual  Report,  AEP,  APCo,  CSPCo,  I&M,  and OPCo have been
        involved in litigation  since 1999 regarding  generating plant emissions
        under  the  Clean Air Act.  Federal  EPA and a number of states  alleged
        APCo,   CSPCo,  I&M,  OPCo  and  eleven   unaffiliated   utilities  made
        modifications  to generating  units at coal-fired  generating  plants in
        violation of the Clean Air Act. Federal EPA filed complaints against AEP
        subsidiaries in U.S. District Court for the Southern District of Ohio. A
        separate  lawsuit  initiated  by  certain  special  interest  groups was
        consolidated with the Federal EPA case. The alleged  modification of the
        generating units occurred over a 20 year period.

               Under  the  Clean  Air  Act,  if  a  plant   undertakes  a  major
        modification that directly results in an emissions increase,  permitting
        requirements might be triggered and the plant may be required to install
        additional pollution control technology. This requirement does not apply
        to  activities  such as routine  maintenance,  replacement  of  degraded
        equipment  or  failed  components,  or  other  repairs  needed  for  the
        reliable,  safe and efficient  operation of the plant. The Clean Air Act
        authorizes  civil  penalties  of up to $27,500 per day per  violation at
        each  generating  unit ($25,000 per day prior to January 30,  1997).  In
        2001 the 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.
<PAGE>
               In  February  2001 the  government  filed a motion  requesting  a
        determination that four projects undertaken on units at Sporn,  Cardinal
        and Clinch River plants do not constitute "routine  maintenance,  repair
        and  replacement"  as used in the  Clean  Air  Act.  The  Circuit  Court
        dismissed the motion as pre-mature. Management believes its maintenance,
        repair and replacement  activities were in conformity with the Clean Air
        Act and intends to vigorously pursue its defense.

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

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

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

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

               The NOx Rule  required  states to submit plans to comply with its
        provisions.  In 2000  Federal  EPA ruled that eleven  states,  including
        states in which  AEGCo's,  APCo's,  CSPCo's,  I&M's,  KPCo's  and OPCo's
        generating  units are located,  failed to submit  approvable  compliance
        plans which could have resulted in the imposition of stringent sanctions
        including  limits on construction of new sources of air emissions,  loss
        of federal highway funding and possible  Federal EPA assumption of state
        air quality  management  programs.  Most of those states have  submitted
        conforming compliance plans and the appeal filed by AEP subsidiaries and
        other utilities in the D.C. Circuit Court to review this ruling has been
        dismissed.

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

               After review,  the D.C. Circuit Court  instructed  Federal EPA to
        justify the methods it used to allocate  allowances  and project  growth
        for both the NOx Rule and the Section  126 Rule.  AEP  subsidiaries  and
        other utilities requested that the D.C. Circuit Court vacate the Section
        126 Rule or suspend  its May 2003  compliance  date.  In August 2001 the
        D.C. Circuit Court issued an order tolling the compliance schedule until
        Federal EPA responded to the Court's remand. On April 30, 2002,  Federal
        EPA announced that May 31, 2004 is the  compliance  date for the Section
        126 Rule.  Federal EPA published a notice in the Federal Register in May
        2002 advising that no changes in the growth  factors used to set the NOx
        budgets  were  warranted.  In June 2002 AEP  subsidiaries  joined  other
        utilities and  industrial  organizations  in seeking a review of Federal
        EPA's action in the D.C. Circuit Court.
<PAGE>
               In  2000  the  Texas  Natural  Resource  Conservation  Commission
        adopted rules  requiring  significant  reductions in NOx emissions  from
        utility  sources,  including CPL and SWEPCo.  The compliance date is May
        2003 for CPL and May 2005 for SWEPCo.

               AEP is installing  selective catalytic reduction (SCR) technology
        to reduce NOx emission.  During 2001 SCR on OPCo's Gavin Plant commenced
        operations.  Installation  of SCR  technology  on Amos  and  Mountaineer
        plants was completed and commenced  operation in May 2002.  Construction
        of SCR technology at certain other AEP generating  units  continues with
        completion scheduled in May 2003 through 2006.

               Our estimates  indicate that AEP's  compliance with the NOx Rule,
        the Texas Natural Resource Conservation  Commission rule and the Section
        126 Rule could result in required capital  expenditures of approximately
        $1.6 billion,  including amounts spent through June 30, 2002.  Estimated
        compliance costs by registrant subsidiaries are as follows:

                                         Estimated
                                     Compliance Costs
                                     ----------------
                                       (in millions)
               AEGCo                       $125
               APCo                         365
               CPL                           57
               CSPCo                        106
               I&M                          202
               KPCo                         160
               OPCo                         606
               SWEPCo                        28

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

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

               At the date of Enron's  bankruptcy AEP had open trading contracts
        and trading  accounts  receivables and payables with Enron. In addition,
        on June 1, 2001,  we  purchased  Houston  Pipe Line  Company  (HPL) from
        Enron.  Various  HPL  related  contingencies  and  indemnities  remained
        unsettled at the date of Enron's bankruptcy.

               In connection  with the  acquisition of HPL, we acquired from BAM
        Lease  Company,  a  now-bankrupt  subsidiary of Enron,  the right to use
        under a 30-year  lease,  with a renewal right for another 20 years,  the
        Bammel gas storage  facility.  The lease  includes the use of the Bammel
        storage reservoir and the related above ground compression, treating and
        delivery  systems.  We also entered into a "right to use" agreement with
        BAM Lease Company which allows us to use  approximately 55 billion cubic
        feet of cushion gas (or pad gas)  required  for the normal  operation of
        the facility.  The Bammel Trust which  purportedly owned the cushion gas
        had entered into a financing  arrangement  with a group of banks.  These
        banks  purported  to have  certain  rights to the cushion gas in certain
        events of default.  We have been informed by the banks of Bammel Trust's
        default under the terms of their financing agreement.  The banks filed a
        lawsuit  against HPL  seeking a  declaratory  judgment  that they have a
        valid and enforceable  security interest in this cushion gas which would
        permit  them to cause  the  withdrawal  of this  gas  from  the  storage
        facility. Management is unable to predict the outcome of this lawsuit or
        its impact on results of operation and cash flows.

               In the  fourth  quarter of 2001 AEP  provided  $47  million  ($31
        million net of tax) for our  estimated  loss from the Enron  bankruptcy.
        The amounts for certain subsidiary registrants were:
<PAGE>
                                                                      Amounts
                                           Amounts                     Net of
        Registrant                        Provided                      Tax
                                  (in millions)
        APCo                                $5.2                       $3.4
        CSPCo                                3.2                        2.1
        I&M                                  3.4                        2.2
        KPCo                                 1.3                        0.8
        OPCo                                 4.3                        2.8

               The amounts provided were based on an analysis of contracts where
        AEP and Enron are  counterparties,  the  offsetting of  receivables  and
        payables,  the  application  of  deposits  from  Enron and  management's
        analysis of the HPL related purchase contingencies and indemnifications.

               If  there  are  any  adverse   unforeseen   developments  in  the
        bankruptcy  proceeding  or in the  lawsuit  related to the  cushion  gas
        financing  agreement,  our future results of operations,  cash flows and
        possibly financial condition could be adversely impacted.

        Energy Market Investigations - Affecting AEP

               In February 2002 the FERC issued an order  directing its Staff to
        conduct a fact-finding  investigation into whether any entity, including
        Enron Corp., manipulated short-term prices in electric energy or natural
        gas markets in the West or  otherwise  exercised  undue  influence  over
        wholesale  prices in the West, for the period January 1, 2000,  forward.
        In April 2002 AEP furnished certain  information to the FERC in response
        to their related data request.

               Pursuant to the FERC's  February  order, on May 8, 2002, the FERC
        issued further data requests,  including  requests for admissions,  with
        respect to certain  trading  strategies  engaged in by Enron Corp.  and,
        allegedly,   traders  of  other   companies   active  in  the  wholesale
        electricity  and ancillary  services  markets in the West,  particularly
        California, during the years 2000 and 2001. This data request was issued
        to AEP as part of a group of over 100 entities designated by the FERC as
        all sellers of wholesale  electricity  and/or ancillary  services to the
        California  Independent  System  Operator  and/or the  California  Power
        Exchange.

               The May 8, 2002 FERC data request  required senior  management to
        conduct an  investigation  into our trading  activities  during 2000 and
        2001 and to  provide  an  affidavit  as to whether we engaged in certain
        trading  practices  that the FERC  characterized  in the data request as
        being  potentially  manipulative.  Senior  management  complied with the
        order and denied our involvement with those trading practices.

               On May 21,  2002,  the FERC issued a further  data  request  with
        respect  to this  matter  to us and over 100 other  market  participants
        requesting  information for the years 2000 and 2001  concerning  "wash",
        "round  trip"  or  "sale/buy   back"  trading  in  the  Western   System
        Coordinating  Council (WSCC),  which involves the sale of an electricity
        product to another company together with a simultaneous  purchase of the
        same product at the same price (collectively,  "wash sales"). Similarly,
        on May 22, 2002, the FERC issued an additional data request with respect
        to this matter to us and other market  participants  requesting  similar
        information  for the same period with respect to the sale of natural gas
        products  in the  WSCC  and  Texas.  After  reviewing  our  records,  we
        responded  to the FERC that we did not  participate  in any "wash  sale"
        transactions  involving power or gas in the relevant market.  We further
        informed  the FERC that  certain of our  traders did engage in trades on
        the  Intercontinental   Exchange,  an  electronic   electricity  trading
        platform owned by a group of electricity  trading  companies,  including
        us, on September 21, 2001,  the day on which all  brokerage  commissions
        for trades on that exchange were donated to charities for the victims of
        the September  11, 2001  terrorist  attacks,  which do not meet the FERC
        criteria for a "wash sale" but do have certain characteristics in common
        with such sales.  In response to a request from the California  attorney
        general for a copy of AEP's responses to the FERC inquires,  we provided
        the pertinent information.
<PAGE>
               The PUCT also issued similar data requests to AEP and other power
        marketers.  AEP  responded  to such  data  request  by the July 2,  2002
        response date. The US Commodity Futures Trading Commission (CFTC) issued
        a subpoena to us on June 17, 2002 requesting information with respect to
        "wash sale" trading practices. We responded to CFTC. In addition, the US
        Department of Justice made a civil investigation  demand to us and other
        electric  generating  companies  concerning  their  investigation of the
        Intercontinental  Exchange.  We have recently  completed a review of our
        trading  activities  in the  United  States  for the  last  three  years
        involving sequential trades with the same terms and counterparties.  The
        revenue from such trading is not material to our  financial  statements.
        We believe that  substantially all these  transactions  involve economic
        substance and risk transference and do not constitute "wash sales".

        FERC Proposed Security Standards

               In July 2002 the FERC published for comment its proposed security
        standards  as  part  of  the  Standards for Market  Design (SMD).  These
        standards are  intended to  ensure  all market participants have a basic
        security program that   effectively   protects  the  electric  grid  and
        related  market activities and  require  compliance  by January 1, 2004.
        The impact of these proposed  standards is far-reaching and has
        significant  penalties for  non-compliance.  These  standards  apply  to
        marketers,  transmission owners, and power producers. For the AEP System
        this includes: regulated and  non-regulated  power  generation   plants,
        transmission systems, distribution  systems, regulated and non-regulated
        energy  trading, and  related  areas  of  business.  These  standards
        represent a significant effort that will  impact the entire AEP  System.
        Unless the cost can be  recovered from customers,  results of operations
        and cash flows would be adversely affected.

        FERC Market Power Mitigation

               A FERC order 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 systems
        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.  No such conference has been held and management is
        unable to predict the timing of any further action by the FERC or its
        affect on future results of operations and cash flows.

        Minority Interest in Finance Subsidiary - Affecting AEP

               In August 2001,  AEP formed  Caddis  Partners,  LLC  (Caddis),  a
        consolidated  subsidiary,  and sold a  non-controlling  preferred member
        interest  in  Caddis  to  an   unconsolidated   special  purpose  entity
        (Steelhead)  for  $750  million.  Under  the  provisions  of the  Caddis
        formation agreements, the preferred member interest receives quarterly a
        preferred return equal to an adjusted floating  reference rate. The $750
        million  received  replaced interim funding used to acquire Houston Pipe
        Line Company in June 2001.

               The  preferred  interest is  supported  by natural  gas  pipeline
        assets and $321.4 million of preferred stock issued by an AEP subsidiary
        to the AEP affiliate  which has the managing  member interest in Caddis.
        Such  preferred  stock is  convertible  into AEP  common  stock upon the
        occurrence of certain events  including  AEP's stock price closing below
        $18.75 for ten  consecutive  trading days. AEP can elect not to have the
        transaction  supported by such preferred stock if the preferred interest
        were  reduced  by $225  million.  In  addition,  Caddis has the right to
        redeem the preferred member interest at any time.

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

               Steelhead  has  the  right  to  terminate  the   transaction  and
        liquidate  Caddis  upon the  occurrence  of certain  events  including a
        default  in the  payment of the  preferred  return.  Steelhead's  rights
        include:  forcing a liquidation of Caddis and acting as the  liquidator,
        and requiring the  conversion  of the $321.4  million of AEP  subsidiary
        preferred stock into AEP common stock. If the preferred  member interest
        exercised its rights to liquidate under these conditions, then AEP would
        evaluate whether to refinance at that time or relinquish the assets that
        support the  preferred  member  interest.  Liquidation  of the preferred
        interest or of Caddis could negatively impact AEP's liquidity.

               Caddis and the AEP subsidiary  which acts as its managing  member
        are each a limited  liability  company,  with a separate  existence  and
        identity  from its  members,  and the  assets of each are  separate  and
        legally  distinct  from AEP. The results of  operations,  cash flows and
<PAGE>
        financial  position of Caddis and such managing member are  consolidated
        with AEP for financial reporting purposes. The preferred member interest
        and  payments  of the  preferred  return are  reported  on AEP's  income
        statement and balance sheet as Minority Interest in Finance Subsidiary.

        Foreign Distribution Projects - Affecting AEP

               We own a 44%  equity  interest  in  Vale,  a  Brazilian  electric
        operating  company which was  purchased for a total of $149 million.  On
        December 1, 2001 we converted a $66 million note  receivable and accrued
        interest  into  a 20%  equity  interest  in  Caiua  (Brazilian  electric
        operating   company),   a  subsidiary  of  Vale.  Vale  and  Caiua  have
        experienced  losses from operations and our investment has been affected
        by the devaluation of the Brazilian Real. The cumulative equity share of
        operating and foreign currency  translation losses through June 30, 2002
        is approximately $47 million and $58 million,  respectively, net of tax.
        The   cumulative   equity  share  of  operating  and  foreign   currency
        translation  losses  through  December  31,  2001 is  approximately  $46
        million and $54 million,  respectively, net of tax. Both investments are
        covered by a put option,  which, if exercised,  requires our partners in
        Vale to purchase our Vale and Caiua  shares at a minimum  price equal to
        the U.S. dollar  equivalent of the original purchase price. As a result,
        management has concluded that the investment  carrying amount should not
        be reduced below the put option value unless it is deemed to be an other
        than temporary  impairment and our partners in Vale are deemed unable to
        fulfill their  responsibilities  under the put option.  In January 2002,
        management evaluated through an independent third-party,  the ability of
        its Vale partners to fulfill their responsibilities under the put option
        agreement  and  concluded  that our  partners  should be able to fulfill
        their responsibilities.

               Management  believes  that  the  decline  in  the  value  of  its
        investment  in Vale in US  dollars  is not other  than  temporary.  As a
        result and pursuant to the put option  agreement,  these losses have not
        been  applied  to  reduce  the  carrying  values  of the Vale and  Caiua
        investments.  As a result we will not recognize any future earnings from
        Vale and Caiua until the operating  losses are  recovered.  In addition,
        our partners have a principal payment due in November 2002 in the amount
        of $55  million.  Our  partners  plan to  refinance  the debt before the
        payment comes due. Should the impairment of our investment  become other
        than  temporary due to our partners in Vale  becoming  unable to fulfill
        their  responsibilities,  it would  have an  adverse  effect  on  future
        results of operations.

               Management will continue to monitor both the status of the losses
        and its  partners  ability  to  fulfill their obligations  under the put
        option.

        Investments in Telecommunications Companies - Affecting AEP

               AEP   provides   telecommunications   services  to  business  and
        telecommunication companies through a broadband fiber optic network. AEP
        conducts  its  operations  through  an  ownership  interest  in a  joint
        venture, AFN Networks, LLC (AFN), and through its AEP Communications and
        C3 subsidiaries.

               Management  is  currently   reassessing  its   telecommunications
        business  strategy and  considering  certain  changes that could include
        additional  investment in AFN,  possible  financial control of the joint
        venture's    operations,    and   a   reorganization    of   its   other
        telecommunications  operations  in order to  optimize  the value of such
        assets.  The  review  of the  telecommunications  business  strategy  is
        expected to be completed  in the third  quarter of 2002.  In  connection
        with the completion of this  assessment and  reorganization  activities,
        management will review its investment in telecommunication companies for
        any impairment of value. Management is unable to determine whether there
        is any impairment  until such  evaluation is complete.  At June 30, 2002
        AEP's investment in telecommunications  companies was approximately $252
        million.

        Other

               AEP and its  subsidiary  registrants  continue  to be involved in
        certain other matters discussed in the 2001 Annual Report.
<PAGE>
           REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
             OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS

        This  is  our  combined  presentation  of  management's  discussion  and
analysis of financial condition, contingencies and other matters for AEP and its
registrant  subsidiaries.  Management's  discussion  and  analysis of results of
operations for AEP and each of its registrant  subsidiaries  for the quarter and
year-to-date  period  ended June 30,  2002 is  presented  with  their  financial
statements earlier in this document.
FINANCIAL CONDITION
        The rating agencies have been  conducting  credit reviews of AEP and its
registrant  subsidiaries as we prepare for corporate  separation.  In April 2002
Moody's  Investors  Service placed AEP and five of its  registrant  subsidiaries
(CPL,  CSPCo,  OPCo,  SWEPCo  and  WTU) on  credit  rating  watch  for  possible
downgrade.  The  review  of  SWEPCo  could  conclude  with more than a one notch
downgrade.  Moody's  confirmed  the  credit  ratings  of four of AEP  registrant
subsidiaries (APCo, I&M, KPCo, and PSO). In May 2002, Standard & Poors confirmed
AEP and its registrant subsidiaries senior unsecured debt rating. First Mortgage
Bond ratings of all the registrant subsidiaries were lowered to "BBB+" from "A".
AEP's commercial paper programs  short-term  ratings of A2 and P2 were confirmed
by Moody's and Standard and Poor's, respectively.
        The review of the  companies'  debt  position and credit rating is being
completed  in  anticipation  of  corporate  separation.  We are working with the
rating  agencies and  providing  information  to support  AEP's  current  credit
rating.  If our  credit  ratings  are  lowered,  the  interest  rates  we pay on
borrowings will potentially rise thereby  increasing our interest expense unless
we can reduce our borrowings.
        At June 30,  2002,  the ratings of AEP's  subsidiaries'  first  mortgage
bonds are listed in the following table:

Company                      Moody's      S&P        Fitch

APCo                         A3           BBB+       A-
CPL                          A3           BBB+       A
CSPCo                        A3           BBB+       A
I&M                          Baa1         BBB+       BBB+
KPCo                         Baa1         BBB+       BBB+
OPCo                         A3           BBB+       A-
PSO                          A1           BBB+       A+
SWEPCo                       A1           BBB+       A
WTU                          A2           BBB+       A

         The  ratings at June 30, 2002 for senior  unsecured  debt are listed in
the following table:

Company                      Moody's      S&P        Fitch

aEP                          Baa1         BBB+       BBB+
AEP Resources*               Baa1         BBB+       BBB+
APCo                         Baa1         BBB+       BBB+
CPL                          Baa1         BBB+       BBB+
CSPCo                        A3           BBB+       A-
I&M                          Baa2         BBB+       BBB
KPCo                         Baa2         BBB+       BBB
OPCo                         A3           BBB+       BBB+
PSO                          A2           BBB+       A
SWEPCo                       A2           BBB+       A-
WTU                           -           BBB+       -
*The  rating  is for a series  of senior  notes  issued  with a
Support Agreement from AEP.
<PAGE>
         Cash from operations and short-term  borrowings provide working capital
and meet other short-term cash needs. We generally use short-term  borrowings to
fund property  acquisitions and construction  until long-term funding mechanisms
are arranged.  Sources of long-term  funding  include  issuance of common stock,
convertible securities,  preferred stock or long-term debt and sale-leaseback or
leasing  agreements.  We operate a money pool and sell accounts  receivables  to
provide liquidity for the domestic electric subsidiaries.  Short-term borrowings
come from the  parent  company's  commercial  paper  program  and are  loaned to
subsidiaries through inter-company notes. The commercial paper program is backed
by $3.5 billion in bank  facilities of which $1 billion  matures in May 2005 and
$2.5 billion matures in May 2003. At June 30, 2002,  approximately  $1.4 billion
was outstanding in commercial paper. In addition,  AEP has a $1.725 billion bank
facility  maturing  in April  2003 that is  available  for debt  refinancing  in
anticipation  of  corporate  separation.  At June 30,  2002,  $600  million  was
outstanding under that facility. We anticipate repayment of the facility through
the  issuance of bonds by certain  subsidiaries.  The pricing on the facility is
based on a spread over LIBOR.
        During the first half of 2002 cash flow from operations was $96 million,
including  $107  million  from a net loss and $912  million  from  depreciation,
amortization and deferred taxes.  Capital  expenditures  including  acquisitions
were $785 million and  dividends on common  stock were $387  million.  Cash from
operations and the issuance of common stock,  common equity units and transition
funding  bonds  provided  funds  to  reduce  debt,  fund  construction  and  pay
dividends. Major construction expenditures included amounts for emission control
technology on several coal-fired generating units (see discussion in Note 8).
        During the fourth  quarter of 2001,  Quaker Coal Co.,  MEMCO Barge Line,
Inc.  and  two  coal-fired  generating  plants  in the UK  were  acquired  using
short-term  borrowings and available cash. Long-term financing  arrangements are
being  negotiated  for  the UK  generating  plants  and  will  be  announced  as
completed.  Completion of this  financing is anticipated in the third quarter of
2002.  Long-term  funding  arrangements  are  often  complex  and  take  time to
complete.
        In  anticipation  of corporate  separation,  CPL and WTU both  initiated
tenders for their first mortgage bonds in July. The cumulative  amounts tendered
for CPL and WTU was $401 million and $89 million,  respectively. In order to pay
for a portion of these retired bonds, as well as previously  retired bonds,  AEP
borrowed  $600 million  under the term loan  facility.  In turn,  AEP loaned the
amounts it borrowed to CPL ($200  million),  CSPCo ($250 million) and OPCo ($150
million).
        In June 2002 we issued 16  million  shares of AEP  common  stock and 6.9
million equity units. We used the proceeds from the issuances of $968 million to
establish a $300 million  cash  liquidity  reserve and to reduce debt.  The cash
reserve  enhances our liquidity and is included in cash and cash  equivalents on
AEP's consolidated balance sheet.
<PAGE>
        Total consolidated plant and property additions including capital leases
for the six months ended June 30, 2002 were $865 million.  The  following  table
shows the plant and property additions by certain registrant subsidiaries:
        Company                     Amount
        -------                     ------
                                (in millions)
        APCo                         $129
        CPL                            65
        I&M                            69
        OPCo                          158
        SWEPCo                         36

Pending and Possible Divestitures

         We  have a  strong  commitment  to  continually  evaluate  the  need to
reallocate  resources  to areas  that  effectively  match  investments  with our
strategy,  provide  greater  potential for meaningful  financial  returns and to
dispose of investments that do not meet these principles.
         In July 2002 we completed the sale of SEEBOARD,  an energy delivery and
power supply business in the UK, receiving cash of  approximately  $1.04 billion
which will be used to reduce debt.  The sale  resulted in a loss of $345 million
(See Note 3).
         We have entered  into a  definitive  agreement to dispose of two of our
Texas  retail  electric  providers  which  serve  retail  residential  and small
commercial customers in Texas. The disposal price will not be determined until a
date  closer to the  consummation  of the  transaction,  which is expected to be
during the fourth quarter of 2002.
         In July 2002 we  reached an  agreement  to sell  CitiPower,  our energy
delivery and retail supply  businesses in Australia.  It is anticipated that AEP
will  receive  approximately  $180 million in cash and the sale will result in a
$125 million loss (See Note 3).
          AEP   provides    telecommunications    services   to   business   and
telecommunication  companies  through  a  broadband  fiber  optic  network.  AEP
conducts its operations  through an ownership  interest in a joint venture,  AFN
Networks, LLC (AFN), and through its AEP Communications and C3 subsidiaries.
        Management  is currently  reassessing  its  telecommunications  business
strategy  and  considering   certain  changes  that  could  include   additional
investment in AFN, possible financial control of the joint venture's operations,
and a  reorganization  of its other  telecommunications  operations  in order to
optimize the value of such assets. The review of the telecommunications business
strategy is expected to be completed in the third quarter of 2002. In connection
with the completion of this assessment and reorganization activities, management
will review its investment in telecommunication  companies for any impairment of
value.  Management is unable to determine  whether there is any impairment until
such   evaluation   is  complete.   At  June  30,  2002  AEP's   investment   in
telecommunications companies was approximately $252 million.

Corporate Separation
        As discussed in the 2001 Annual Report,  we have filed with the FERC and
SEC seeking approval to separate our regulated and unregulated  operations.  Our
<PAGE>
plan for corporate  separation  allows us to meet the  requirements of Texas and
Ohio restructuring legislation. We intend to transfer the generation assets from
the integrated electric operating companies in Ohio and Texas (CSPCo,  OPCo, CPL
and WTU) to  unregulated  generation  companies.  We proposed  amendments to the
power pooling  agreements  for all  operating  companies.  Only those  operating
companies  that continue to exist as integrated  utilities  would be included in
the amended power pooling agreements,  which would govern energy exchanges among
members and the  allocation  of their off system  purchases  and sales.  Several
state  commissions,  wholesale  customer  groups  and other  interested  parties
intervened in the FERC proceeding. We have negotiated settlement agreements with
the six state regulatory commissions and other major intervenors. The settlement
agreements have been filed at the FERC for  review and  approval.  FERC  and SEC
approval of our corporate separation plan is required for its implementation. In
order to  execute  this  separation,  we will be required to retire various debt
securities and to transfer assets between legal entities.
RTO Formation
         As discussed in the 2001 Annual Report, FERC Order No. 2000 and many of
the settlement  agreements with the state regulatory  commissions to approve the
AEP-CSW  merger  required  the transfer of control of our transmission system to
RTOs. Certain  AEP subsidiaries  participated  in  the formation of the Alliance
RTO.  Other subsidiaries are members of ERCOT or SPP.
         The FERC  expressed  its opinion  that large RTOs will  better  support
competitive,  reliable  electric service and rejected the Alliance RTO's filing.
In May 2002 AEP announced an agreement  with the PJM  Interconnection  to pursue
terms for certain subsidiares to participate in its RTO.  Final  agreements  are
expected  to be  negotiated. In July 2002 the FERC tentatively  approved certain
AEP subsidiaries' decision to join PJM subject to certain conditions being  met.
The performance of these conditions are only partially under AEP's control.
         In other RTO developments FERC recently accepted conditionally, filings
related to a proposed consolidation of the Midwest Independent  System  Operator
(MISO) and the SPP.  In that order the FERC  required  the AEP  subsidiaries  in
SPP to file reasons why those subsidiaries  should not be required to join MISO.
AEP filed with the FERC a response that additional analysis  was required  prior
to AEP making an RTO decision. The SPP companies are also regulated by state
public utility commissions, and the Louisiana and Arkansas commissions also
filed responses to the FERC's RTO order indicating that additional analysis was
required.
         Management is unable to predict the final outcome of these transmission
regulatory  actions and  proceedings or their impact on the timing and operation
of RTOs, our transmission operations or results of operations and cash flows.
OTHER MATTERS
Industry Restructuring
         As discussed in Note 4 and the 2001 Annual  Report,  restructuring  and
customer choice began in four of the eleven state retail  jurisdictions in which
the AEP electric utility companies operate.  Restructuring  legislation provides
for a transition  from  cost-based  regulation  of bundled  electric  service to
customer  choice and market  pricing  for the  supply of  electricity.  Customer
choice of  electricity  supplier began on January 1, 2001 for Ohio customers and
on January 1, 2002,  for Michigan,  Texas and Virginia  customers.  In the Texas
jurisdiction  competition  began in the ERCOT  area but was  delayed  in the SPP
area. In Ohio, Michigan and Virginia virtually all customers continue to receive
electric  generation,  transmission and distribution  services from our electric
operating companies.
         On June 27, 2002, the Ohio Consumers' Counsel,  Industrial Energy Users
- Ohio and  American  Municipal  Power - Ohio  filed a  complaint  with the PUCO
alleging  that  CSPCo  and  OPCo  have  violated  the  PUCO's  orders  regarding
implementation  of their  transition  plan and violated other  applicable law by
failing  to  participate  in an  RTO.
<PAGE>
         The  complainants  seek, among  other  relief, an  order from  the PUCO
suspending collection of transition charges by CSPCo and OPCo until transfer  of
control  of their  transmission  assets  has occurred and imposing a $25,000 per
company forfeiture for  each  day  AEP fails to comply  with its  commitment  to
transfer control of transmission assets to an RTO.
         Due to FERC delays in the approval of our RTO  filings,  CSPCo and OPCo
have been unable to  implement  their RTO plan.  Management is unable to predict
the  timing  of FERC's  final  approval  of RTOs and the  timing of an RTO being
operational or the outcome of this proceeding before the PUCO.
         In 2001 the  PUCT  issued  an  order  requiring  CPL to  reduce  future
distribution rates by $54.8 million over a five-year period beginning January 1,
2002 in order to return  estimated  excess earnings for 1999, 2000 and 2001. The
Texas Restructuring  Legislation  intended that excess earnings would be used to
reduce  stranded  cost.  Final stranded cost amounts and the treatment of excess
earnings will be determined in the 2004 true-up  proceeding.  The PUCT currently
estimates that CPL will have no stranded cost and has ordered the rate reduction
to return excess earnings,  pending the outcome of the 2004 true-up  proceeding.
CPL expensed excess earnings amounts in 1999, 2000 and 2001.  Consequently,  the
order has no effect on reported net income.
         Beginning  January 1, 2002,  fuel costs for CPL and WTU in ERCOT are no
longer  subject  to  PUCT  fuel  reconciliation   proceedings  under  the  Texas
Restructuring  Legislation.  Consequently,  CPL and WTU will  file a final  fuel
reconciliation  with the PUCT to reconcile  their fuel costs  through the period
ending  December 31, 2001.  These final fuel  balances  will be included in each
company's 2004 true-up proceeding. The elimination of the fuel clause recoveries
in 2002 in Texas will  subject AEP, CPL and WTU to the risk of fuel market price
increases and could adversely affect future results of operations.
         Two unaffiliated Texas utilities reached settlement agreements approved
by  the  PUCT  regarding  recovery  of  stranded  generation  costs.  CPL is not
presently  engaged in any settlement  discussions with the PUCT. Under the Texas
Legislation, a 2004 true-up proceeding will determine recovery of stranded costs
including  final  fuel  recovery  balances,   net  regulatory  assets,   certain
environmental  costs,  accumulated  excess  earnings  and  other  issues.  CPL's
generation-related  regulatory  assets subject to recovery as stranded costs are
approximately  $1.1 billion of which $949 million has been  securitized  pending
the 2004 true-up proceeding's determination of stranded costs recovery including
the recovery of stranded generation-related regulatory assets. WTU and SWEPCo do
not have any recoverable Texas generation-related regulatory assets.
         In the event CPL,  SWEPCo,  and WTU are unable  after the 2004  true-up
proceeding  to recover all or a portion of their  generation-related  regulatory
assets,  unrecovered  fuel  balances,  stranded  costs and  other  restructuring
related costs, it could have a material adverse effect on results of operations,
cash flows and possibly financial condition.
<PAGE>
Litigation
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M,
and OPCo
        As discussed in the 2001 Annual Report,  AEP, APCo, CSPCo, I&M, and OPCo
have been involved in litigation since 1999 regarding generating plant emissions
under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo,
I&M, OPCo and eleven  unaffiliated  utilities made  modifications  to generating
units at coal-fired generating plants in violation of the Clean Air Act. Federal
EPA filed  complaints  against AEP  subsidiaries in U.S.  District Court for the
Southern  District of Ohio.  A separate  lawsuit  initiated  by certain  special
interest  groups  was  consolidated  with the  Federal  EPA  case.  The  alleged
modification of the generating units occurred over a 20 year period.
         Under the Clean Air Act,  if a plant  undertakes  a major  modification
that directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional  pollution control
technology.  This  requirement  does not  apply to  activities  such as  routine
maintenance,  replacement of degraded equipment or failed  components,  or other
repairs needed for the reliable,  safe and efficient operation of the plant. The
Clean Air Act authorizes  civil penalties of up to $27,500 per day per violation
at each generating unit ($25,000 per day prior to January 30, 1997). In 2001 the
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.
        In  February   2001  the   government   filed  a  motion   requesting  a
determination  that four  projects  undertaken  on units at Sporn,  Cardinal and
Clinch  River  plants  do  not  constitute  "routine  maintenance,   repair  and
replacement"  as used in the Clean Air Act.  The  Circuit  Court  dismissed  the
motion as premature. Management believes its maintenance, repair and replacement
activities  were in conformity  with the Clean Air Act and intends to vigorously
pursue its defense.
        Management  is unable to estimate  the loss or range of loss  related to
the contingent liability for civil penalties under the Clear Air Act proceedings
and  unable to predict  the timing of  resolution  of these  matters  due to the
number of  alleged  violations  and the  significant  number of issues yet to be
determined by the Court.  In the event the AEP System  companies do not prevail,
any capital and operating costs of additional  pollution  control equipment that
may be required as well as any penalties  imposed would adversely  affect future
results of operations,  cash flows and possibly financial  condition unless such
costs  can  be  recovered   through   regulated  rates  and  market  prices  for
electricity.
        In December 2000 Cinergy Corp., an unaffiliated utility,  which operates
certain  plants  jointly  owned by CSPCo,  reached a  tentative  agreement  with
Federal EPA and other parties to settle  litigation  regarding  generating plant
emissions  under the Clean Air Act.  Negotiations  are  continuing  between  the
parties in an attempt to reach  final  settlement  terms.  Cinergy's  settlement
could impact the operation of Zimmer Plant and W.C. Beckjord  Generating Station
Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement
is reached,  CSPCo will be unable to determine  the  settlement's  impact on its
jointly owned facilities and its future results of operations and cash flows.
<PAGE>
NOx Reductions - Affecting AEP, AEGCo,  APCo,  CPL,  CSPCo,  I&M, KPCo, OPCo and
SWEPCo
        Federal EPA issued a NOx Rule  requiring  substantial  reductions in NOx
emissions in a number of eastern states,  including  certain states in which the
AEP  System's  generating  plants are  located.  The NOx Rule has been upheld on
appeal. The compliance date for the NOx Rule is May 31, 2004.
        The NOx  Rule  required  states  to  submit  plans  to  comply  with its
provisions.  In 2000 Federal EPA ruled that eleven states,  including  states in
which AEGCo's,  APCo's,  CSPCo's,  I&M's, KPCo's and OPCo's generating units are
located,  failed to submit approvable compliance plans which could have resulted
in the imposition of stringent sanctions including limits on construction of new
sources of air emissions,  loss of federal highway funding and possible  Federal
EPA assumption of state air quality  management  programs.  Most of those states
have  submitted  conforming  compliance  plans  and  the  appeal  filed  by  AEP
subsidiaries and other utilities in the D.C. Circuit Court to review this ruling
has been dismissed.
        In 2000  Federal EPA also  adopted a revised rule (the Section 126 Rule)
granting petitions filed by certain northeastern states under the Clean Air Act.
The rule imposes  emissions  reduction  requirements  comparable to the NOx Rule
beginning May 1, 2003, for most of AEP's coal-fired  generating units.  Affected
utilities including certain AEP operating companies, petitioned the D.C. Circuit
Court to review the Section 126 Rule.
        After review,  the D.C. Circuit Court instructed  Federal EPA to justify
the methods it used to allocate  allowances  and project growth for both the NOx
Rule and the Section 126 Rule. AEP  subsidiaries  and other utilities  requested
that the D.C.  Circuit Court vacate the Section 126 Rule or suspend its May 2003
compliance  date. In August 2001 the D.C.  Circuit Court issued an order tolling
the  compliance  schedule until Federal EPA responds to the Court's  remand.  On
April 30, 2002,  Federal EPA announced that May 31, 2004 is the compliance  date
for the Section 126 Rule. Federal EPA published a notice in the Federal Register
in May 2002 advising  that no changes in the growth  factors used to set the NOx
budgets were warranted. In June 2002 AEP subsidiaries joined other utilities and
industrial organizations in seeking a review of Federal EPA's action in the D.C.
Circuit Court.
        In 2000 the Texas Natural Resource Conservation Commission adopted rules
requiring  significant   reductions  in  NOx  emissions  from  utility  sources,
including CPL and SWEPCo.  The compliance  date is May 2003 for CPL and May 2005
for SWEPCo.
        AEP is installing  selective  catalytic  reduction  (SCR)  technology to
reduce NOx emission. During 2001 SCR on OPCo's Gavin Plant commenced operations.
Installation of SCR technology on Amos and Mountaineer  plants was completed and
commenced operation in May 2002. Construction of SCR technology at certain other
AEP generating  units  continues with  completion  scheduled in May 2003 through
2006.
        Our estimates  indicate  that AEP's  compliance  with the NOx Rule,  the
Texas Natural  Resource  Conservation  Commission  rule and the Section 126 Rule
could result in required  capital  expenditures of  approximately  $1.6 billion,
including amounts spent through June 30, 2002.
        The following  table shows the estimated  compliance cost for certain of
AEP's registrant subsidiaries.

        Company               Amount
        -------               ------
                      (in millions)

        APCo              $365
        CPL                 57
        I&M                202
        OPCo               606
        SWEPCo              28

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

Enron Bankruptcy -  Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
         At the date of Enron's  bankruptcy  AEP had open trading  contracts and
trading  accounts  receivables and payables with Enron. In addition,  on June 1,
2001,  we  purchased  Houston Pipe Line  Company  (HPL) from Enron.  Various HPL
related  contingencies and indemnities remained unsettled at the date of Enron's
bankruptcy.
         In connection  with the  acquisition of HPL, we acquired from BAM Lease
Company,  a now-bankrupt  subsidiary of Enron,  the right to use under a 30-year
lease,  with a renewal  right for  another  20 years,  the  Bammel  gas  storage
facility.  The lease  includes the use of the Bammel  storage  reservoir and the
related above ground compression, treating and delivery systems. We also entered
into a "right to use"  agreement  with BAM Lease  Company which allows us to use
approximately 55 billion cubic feet of cushion gas (or pad gas) required for the
normal operation of the facility.  The Bammel Trust which  purportedly owned the
cushion gas had entered into a financing  arrangement with a group of banks. The
banks  purported to have certain  rights to the cushion gas in certain events of
default.  We have been informed by the banks of Bammel Trust's default under the
terms of their  financing  agreement.  The  banks  filed a lawsuit  against  HPL
seeking a declaratory  judgment that they have a valid and enforceable  security
interest in this cushion gas which would permit them to cause the  withdrawal of
this gas from the storage facility.  Management is unable to predict the outcome
of this lawsuit or its impact on results of operation and cash flows.
        In the fourth  quarter of 2001 AEP provided $47 million ($31 million net
of tax) for our  estimated  loss  from the Enron  bankruptcy.  The  amounts  for
certain subsidiary registrants were:
                                                                      Amounts
                                           Amounts                     Net of
        Registrant                        Provided                      Tax
                                  (in millions)

        APCo                                $5.2                       $3.4
        CSPCo                                3.2                        2.1
        I&M                                  3.4                        2.2
        KPCo                                 1.3                        0.8
        OPCo                                 4.3                        2.8

        The amounts  provided  were based on an analysis of contracts  where AEP
and Enron are  counterparties,  the offsetting of receivables and payables,  the
application of deposits from Enron and management's  analysis of the HPL related
purchase contingencies and indemnifications.
<PAGE>
           If there are any adverse  unforeseen  developments  in the bankruptcy
proceeding or in the lawsuit related to the cushion gas financing agreement, our
future results of operations,  cash flows and possibly financial condition could
be adversely impacted.
Energy Market Investigations - Affecting AEP
        In February 2002 the FERC issued an order directing its Staff to conduct
a fact-finding  investigation  into whether any entity,  including  Enron Corp.,
manipulated  short-term  prices in electric energy or natural gas markets in the
West or otherwise  exercised undue influence over wholesale  prices in the West,
for the period  January 1, 2000,  forward.  In April 2002 AEP furnished  certain
information to the FERC in response to their related data request.
        Pursuant to the FERC's  February  order, on May 8, 2002, the FERC issued
further  data  requests,  including  requests  for  admissions,  with respect to
certain trading strategies engaged in by Enron Corp. and, allegedly,  traders of
other  companies  active in the wholesale  electricity  and  ancillary  services
markets in the West,  particularly  California,  during the years 2000 and 2001.
This data  request  was  issued  to AEP as part of a group of over 100  entities
designated by the FERC as all sellers of wholesale  electricity and/or ancillary
services to the California  Independent  System  Operator  and/or the California
Power Exchange.
        The May 8, 2002 FERC data request required senior  management to conduct
an investigation into our trading activities during 2000 and 2001 and to provide
an affidavit as to whether we engaged in certain trading practices that the FERC
characterized  in the data  request as being  potentially  manipulative.  Senior
management complied with the order and denied our involvement with those trading
practices.
        On May 21, 2002,  the FERC issued a further data request with respect to
this matter to us and over 100 other market participants  requesting information
for the years 2000 and 2001 concerning  "wash",  "round trip" or "sale/buy back"
trading in the Western System  Coordinating  Council (WSCC),  which involves the
sale of an electricity  product to another company  together with a simultaneous
purchase of the same  product at the same price  (collectively,  "wash  sales").
Similarly,  on May 22,  2002,  the FERC issued an  additional  data request with
respect to this matter to us and other market  participants  requesting  similar
information for the same period with respect to the sale of natural gas products
in the WSCC and Texas.  After  reviewing  our records,  we responded to the FERC
that we did not participate in any "wash sale"  transactions  involving power or
gas in the  relevant  market.  We further  informed the FERC that certain of our
traders did engage in trades on the  Intercontinental  Exchange,  an  electronic
electricity  trading platform owned by a group of electricity trading companies,
including us, on September 21, 2001, the day on which all brokerage  commissions
for trades on that  exchange  were donated to  charities  for the victims of the
September 11, 2001 terrorist attacks,  which do not meet the FERC criteria for a
"wash sale" but do have certain  characteristics  in common with such sales.  In
response to a request from the California  attorney  general for a copy of AEP's
responses to the FERC inquires, we provided the pertinent information.
        The PUCT also  issued  similar  data  requests  to AEP and  other  power
marketers. AEP responded to such data request by the July 2, 2002 response date.
<PAGE>
The US Commodity Futures Trading Commission (CFTC) issued a subpoena on June 17,
2002 requesting  information with respect to "wash sale" trading  practices.  We
responded  to CFTC.  In  addition,  the US  Department  of Justice  made a civil
investigation  demand to us and other electric generating  companies  concerning
their investigation of the Intercontinental Exchange. We have recently completed
a review of our trading activities in the United States for the last three years
involving sequential trades with the same terms and counterparties.  The revenue
from such trading is not material to our financial  statements.  We believe that
substantially  all  these  transactions  involve  economic  substance  and  risk
transference and do not constitute "wash sales".
Minority Interest in Finance Subsidiary - Affecting AEP
        In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated
subsidiary, and sold a non-controlling preferred member interest in Caddis to an
unconsolidated  special purpose entity  (Steelhead) for $750 million.  Under the
provisions of the Caddis  formation  agreements,  the preferred  member interest
receives  quarterly a preferred return equal to an adjusted  floating  reference
rate. The $750 million received replaced interim funding used to acquire Houston
Pipe Line Company in June 2001.
        The preferred  interest is supported by natural gas pipeline  assets and
$321.4  million  of  preferred  stock  issued  by an AEP  subsidiary  to the AEP
affiliate which has the managing member interest in Caddis. Such preferred stock
is  convertible  into AEP common  stock upon the  occurrence  of certain  events
including  AEP's stock price  closing below $18.75 for ten  consecutive  trading
days.  AEP can elect not to have the  transaction  supported  by such  preferred
stock if the  preferred  interest  were  reduced by $225  million.  In addition,
Caddis has the right to redeem the preferred member interest at any time.
        The initial period of the preferred  interest is through August 2006. At
the end of the initial  period,  Caddis will either  reset the  preferred  rate,
re-market the preferred member interests to new investors,  redeem the preferred
member interests,  in whole or in part including accrued return, or liquidate in
accordance with the provisions of applicable agreements.
        Steelhead  has the right to  terminate  the  transaction  and  liquidate
Caddis upon the occurrence of certain events  including a default in the payment
of the preferred return.  Steelhead's  rights include:  forcing a liquidation of
Caddis and acting as the liquidator,  and requiring the conversion of the $321.4
million  of AEP  subsidiary  preferred  stock  into  AEP  common  stock.  If the
preferred  member  interest  exercised  its  rights  to  liquidate  under  these
conditions,  then AEP  would  evaluate  whether  to  refinance  at that  time or
relinquish the assets that support the preferred member interest. Liquidation of
the preferred interest or of Caddis could negatively impact AEP's liquidity.
Foreign Distribution Projects - Affecting AEP
        We own a 44% equity  interest in Vale,  a Brazilian  electric  operating
company which was purchased for a total of $149 million.  On December 1, 2001 we
converted a $66 million note  receivable and accrued  interest into a 20% equity
interest in Caiua (Brazilian electric operating company),  a subsidiary of Vale.
Vale and Caiua have  experienced  losses from  operations and our investment has
been affected by the  devaluation of the Brazilian  Real. The cumulative  equity
<PAGE>
share of operating and foreign currency translation losses through June 30, 2002
is  approximately  $47 million and $58  million,  respectively,  net of tax. The
cumulative  equity share of operating and foreign  currency  translation  losses
through  December  31,  2001 is  approximately  $46  million  and  $54  million,
respectively,  net of tax. Both investments are covered by a put option,  which,
if  exercised,  requires  our  partners in Vale to  purchase  our Vale and Caiua
shares at a minimum  price equal to the U.S.  dollar  equivalent of the original
purchase  price.  As a result,  management  has  concluded  that the  investment
carrying  amount  should not be reduced  below the put option value unless it is
deemed to be an other than  temporary  impairment  and our  partners in Vale are
deemed unable to fulfill their responsibilities under the put option. In January
2002,  management evaluated through an independent  third-party,  the ability of
its Vale  partners  to  fulfill  their  responsibilities  under  the put  option
agreement  and  concluded  that our  partners  should be able to  fulfill  their
responsibilities.
        Management  believes that the decline in the value of its  investment in
Vale in US dollars is not other than temporary.  As a result and pursuant to the
put option agreement,  these losses have not been applied to reduce the carrying
values of the Vale and Caiua investments.  As a result we will not recognize any
future earnings from Vale and Caiua until the operating losses are recovered. In
addition,  our  partners  have a principal  payment due in November  2002 in the
amount of $55  million.  Our  partners  plan to  refinance  the debt  before the
payment comes due.  Should the  impairment of our  investment  become other than
temporary  due  to our  partners  in  Vale  becoming  unable  to  fulfill  their
responsibilities,  it  would  have  an  adverse  effect  on  future  results  of
operations.
        Management will continue to  monitor  both  the status of the losses and
its partners ability to fulfill their obligations under the put option.
FERC Proposed Security Standards
        In July 2002 the FERC published for comment its proposed security
standards as part of the Standards for Market Design (SMD). These standards are
intended to ensure all market participants have a basic security program that
effectively  protects the  electric  grid and related  market  activities  and
require  compliance  by January 1, 2004. The impact of these proposed  standards
is far-reaching and has significant  penalties for  non-compliance.  These
standards apply to marketers, transmission  owners,  and power  producers.  For
the AEP System this  includes: regulated and  non-regulated  power  generation
plants,  transmission  systems, distribution  systems,  regulated and
non-regulated  energy trading, and related areas of business.  These  standards
represent a  significant  effort that will impact the entire AEP System.  Unless
the cost can be recovered from  customers, results of operations and cash flows
would be adversely affected.

FERC Market Power Mitigation

        A FERC order 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 systems 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.  No such conference has been
held and management is unable to predict the timing of any further action by the
FERC or its affect on future results of operations and cash flows.

Other
        AEP and its  subsidiary  registrants  continue to be involved in certain
other matters discussed in the 2001 Annual Report.
New Accounting Standard
        In June 2002, the FASB's  Emerging Issues Task Force (EITF) in Issue No.
02-3  "Accounting  for Contracts  Involved in Energy Trading and Risk Management
Activities", reached a consensus that energy trading contracts (whether realized
or unrealized and whether financially or physically settled) should be shown net
in the  income  statement  and  that  expanded  disclosures  of  energy  trading
activities  are required.  This  consensus is effective for periods ending after
<PAGE>
July 15, 2002 and  reclassification  of prior period  amounts is  required.  Our
adoption of EITF Issue No. 02-3 in the third quarter 2002  financial  statements
will lead to a material  decrease in both revenues and purchased energy expense.
There will be no impact on  results of  operations.  Previous  guidance  in EITF
Issue No. 98-10  "Accounting  for Contracts  Involved in Energy Trading and Risk
Management Activities",  permitted settled forward energy trading contract sales
and  purchases  to be shown  either  gross or net in the income  statement.  AEP
currently  records,  and reports upon  settlement,  sales under forward  trading
contracts as revenues and purchases under forward trading contracts as purchased
energy expense.
<PAGE>
        The table  below  shows the amounts of  revenues  and  purchased  energy
expense  that AEP would  report if forward  sales and  purchase  contracts  that
settle  financially were accounted for on a net basis. The  determination of net
trading  revenues  under EITF Issue No. 02-3 may yield a  different  result than
calculating net revenues on the basis of financially settled  transactions only.
We are  currently  assessing  the  application  of EITF Issue No. 02-3 to report
trading transactions on a net basis.
<TABLE>
<CAPTION>
                                                        Six Months Ended June 30,
                                                         2002                         2001
                                                               (in millions)
                                                Gross          Net          Gross            Net
                                                -----          ---          -----            ---
<S>                                          <C>            <C>           <C>             <C>
Revenues:
    Electricity Marketing and Trading        $ 17,525       $4,042        $18,831         $4,788
    Gas Marketing and Trading                   8,477        1,014          7,203            573
    Domestic Electricity Delivery               1,694        1,694          1,672          1,672
    Other Investments                             246          246            238            238
                                              -------       ------        -------         ------
    Total                                     $27,942       $6,996        $27,944         $7,271
                                              =======       ======        =======         ======

                                                Gross          Net          Gross            Net
                                                -----          ---          -----            ---
Fuel and Purchased Energy Expense:
    Electricity Marketing and Trading        $ 15,046       $1,563        $16,945         $2,902
    Gas Marketing and Trading                   8,602        1,139          6,939            309
    Other Investments                             165          165            104            104
                                              -------       ------        -------         ------
    Total                                     $23,813       $2,867        $23,988         $3,315
                                              =======       ======        =======         ======
</TABLE>
<PAGE>
           QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks - Affecting AEP, AEGCo,  APCo, CPL,  CSPCo,  I&M, KPCo,  OPCo, PSO,
SWEPCo and WTU
        As a major  power  producer  and  trader of  wholesale  electricity  and
natural gas, we have certain market risks  inherent in our business  activities.
These risks include commodity price risk,  interest rate risk,  foreign exchange
risk and credit risk.  They represent the risk of loss that may impact us due to
changes in the underlying market prices or rates.
        Policies and procedures have been established to identify,  assess,  and
manage  market risk  exposures in our day to day  operations.  Our risk policies
have been reviewed with the Board of  Directors,  approved by a Risk  Management
Committee  and  administered  by a  Chief  Risk  Officer.  The  Risk  Management
Committee   establishes   risk   limits,   approves   risk   policies,   assigns
responsibilities  regarding the  oversight  and  management of risk and monitors
risk  levels.  This  committee  receives  daily,  weekly,  and  monthly  reports
regarding compliance with policies,  limits and procedures.  The committee meets
monthly and  consists of the Chief Risk  Officer,  Chief  Credit  Officer,  V.P.
Market Risk Oversight, and senior financial and operating managers.
        We use a risk measurement  model which calculates Value at Risk (VaR) to
measure our commodity  price risk. The VaR is based on the variance - covariance
method using  historical  prices to estimate  volatilities  and correlations and
assuming a 95% confidence level and a one-day holding period.  Based on this VaR
analysis, at June 30, 2002 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 high, average, and low market
risk as measured by VaR for the:
          Six Months Ended      Year Ended
              June 30,         December 31,
               2002               2001
               ----               ----
          High Average Low   High Average Low
           (in millions)      (in millions)

AEP        $22    $12   $6    $28    $14   $5

APCo         3      2    1      4      1    -
CPL          -      -    -      3      1    -
CSPCo        2      1    -      2      1    -
I&M          2      1    -      3      1    -
KPCo         1      -    -      1      -    -
OPCo         3      1    -      3      1    -
PSO          -      -    -      2      1    -
SWEPCo       -      -    -      3      1    -
WTU          -      -    -      1      1    -

        We also  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 weekly prices.  The risk of potential
loss in fair value  attributable to AEP's exposure to interest rates,  primarily
related to long-term  debt with fixed interest  rates,  was $639 million at June
30, 2002 and $673  million at December  31,  2001.  However,  since we would not
expect to liquidate our entire debt  portfolio in a one year holding  period,  a
near term change in  interest  rates  should not  materially  affect  results of
operations or consolidated financial position.
          AEGCo  is not  exposed  to risk  from  changes  in  interest  rates on
short-term and long-term  borrowings used to finance  operations since financing
costs are recovered through the unit power agreements.
<PAGE>
          AEP is exposed to risk from  changes in the market  prices of coal and
natural gas used to generate electricity where generation is no longer regulated
or where existing fuel clauses are suspended or frozen. The protection  afforded
by  fuel  clause   recovery   mechanisms  has  either  been  eliminated  by  the
implementation  of customer choice in Ohio (effective  January 1, 2001 for CSPCo
and OPCo) and in the ERCOT area of Texas (effective  January 1, 2002 for CPL and
WTU) or frozen by settlement agreements in Indiana,  Michigan and West Virginia.
To the extent the fuel  supply of the  generating  units in these  states is not
under fixed price  long-term  contracts AEP is subject to market price risk. AEP
continues to be protected against market price changes by active fuel clauses in
Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.
        We employ 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.   However,  we  engage  in  trading  of
electricity,  gas and to a lesser  degree coal,  oil,  natural gas liquids,  and
emission  allowances  and as a result the Company is subject to price risk.  The
amount of risk  taken by the  traders is  controlled  by the  management  of the
trading  operations and the Company's Chief Risk Officer and his staff. When the
risk  from  trading  activities  exceeds  certain   pre-determined  limits,  the
positions  are  modified  or  hedged  to reduce  the risk to the  limits  unless
specifically approved by the Risk Management Committee.
        We employ  fair value  hedges,  cash flow  hedges and swaps 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 cash flow forward hedge contracts to lock-in prices on certain
power  trading  transactions  and certain  transactions  denominated  in foreign
currencies where deemed necessary. International subsidiaries use currency swaps
to hedge exchange rate  fluctuations in debt denominated in foreign  currencies.
We do not hedge all foreign currency exposure.
        AEP limits credit risk by extending  unsecured  credit to entities based
on internal ratings.  In addition,  AEP uses Moody's Investor Service,  Standard
and Poor's and qualitative and  quantitative  data to  independently  assess the
financial  health  of   counterparties  on  an  ongoing  basis.  This  data,  in
conjunction with the ratings information,  is used to determine appropriate risk
parameters.   AEP  also   requires   cash   deposits,   letters  of  credit  and
parental/affiliate  guarantees as security from certain below  investment  grade
counterparties in our normal course of business.
        We trade  electricity  and gas contracts  with numerous  counterparties.
Since our open energy  trading  contracts  are valued based on changes in market
prices of the related  commodities,  our exposures change daily. We believe that
our credit and market  exposures  with any one  counterparty  is not material to
financial  condition at June 30, 2002. At June 30, 2002  approximately 8% of the
counterparties  were below investment grade as expressed in terms of Net Mark to
Market Assets.  Net Mark to Market Assets  represents  the aggregate  difference
(either positive or negative) between the forward market price for the remaining
term of the contract and the contractual price. The following table approximates
counterparty credit quality and exposure for AEP.
<PAGE>
                           Futures,
                           Forwards and
Counterparty               Swap Contracts   Options       Total
 Credit Quality:
June 30, 2002
                                        (in millions)
AAA/Exchanges              $ -              $51            $ 51
AA                            115           -               115
A                             327           -               327
BBB                           784             7             791
Below Investment
  Grade                       103             2             105
                           ------           ---          ------

  Total                    $1,329           $60          $1,389
                           ======           ===          ======

             The  counterparty  credit  quality and exposure for the  registrant
subsidiaries  is  generally  consistent  with that of AEP.
        We enter into  transactions  for  electricity and natural gas as part of
wholesale  trading  operations.  Electric and gas transactions are executed over
the counter with  counterparties  or through brokers.  Gas transactions are also
executed  through  brokerage  accounts with brokers who are registered  with the
Commodity Futures Trading Commission. Brokers and counterparties require cash or
cash related instruments to be deposited on these transactions as margin against
open  positions.  The combined margin deposits at June 30, 2002 and December 31,
2001 were $241 million and $55 million. These margin accounts are restricted and
therefore are not included in cash and cash equivalents on the Balance Sheet. We
can be subject to further margin  requirements  should related  commodity prices
change.
           We  recognize  the net change in the fair  value of all open  trading
contracts, a practice commonly called mark-to-market  accounting,  in accordance
with  generally  accepted  accounting  principles  and include the net change in
mark-to-market  amounts on a net  discounted  basis in revenues.  The marking to
market of open trading  contracts in the second  quarter of 2002  resulted in an
unrealized  increase  in revenues  of $40  million  and  unrealized  increase in
revenues of $87 million year-to-date.  The fair value of open short-term trading
contracts are based on exchange prices and broker quotes. The fair value of open
long-term  trading  contracts  are based mainly on Company  developed  valuation
models.  This fair value is present valued and reduced by  appropriate  reserves
for  counterparty  credit risks and liquidity  risk. The models are derived from
internally  assessed  market  prices with the  exception of the NYMEX gas curve,
where we use daily  settled  prices.  Forward  price  curves are  developed  for
inclusion in the model based on broker quotes and other  available  market data.
The curves are within the range  between the bid and ask prices.  The end of the
month  liquidity  reserve is based on the  difference in price between the price
curve and the bid price of the bid ask prices if we have a long position and the
ask  price  if we  have a  short  position.  This  provides  for a  conservative
valuation net of the reserves.
           The  use of  these  models  to  fair  value  open  long-term  trading
contracts has inherent risks relating to the underlying  assumptions employed by
such models. Independent controls are in place to evaluate the reasonableness of
the price  curve  models.  Significant  adverse or  favorable  effects on future
results of operations and cash flows could occur if market  prices,  at the time
of settlement, do not correlate with the Company developed price models.
<PAGE>
           The  effect on the  Consolidated  Statements  of Income of marking to
market  open   electricity   trading   contracts  in  the  Company's   regulated
jurisdictions  is  deferred  as  regulatory  assets or  liabilities  since these
transactions  are  included  in  cost  of  service  on a  settlement  basis  for
ratemaking purposes. Unrealized mark-to-market gains and losses from trading are
reported as assets and liabilities, respectively.
             The  following  table shows net  revenues  (revenues  less fuel and
purchased energy expense) and their relationship to the mark-to-market  revenues
(the change in fair value of open trading positions).
                                                       Six Months Ended
                                                              June 30,
                                                                 2002
                                                           (in millions)
Revenues (including mark-to-market adjustment)                 $27,942
Fuel and Purchased Energy Expense                               23,813
                                                               -------
Net Revenues                                                   $ 4,129
                                                               =======
Mark-to-Market Revenues on Open Trading Positions                  $87*
                                                                   ===
Percentage of Net Revenues Represented by
 Mark-to-Market on Open Trading Positions                            2%
                                                                     =

*Excludes  reversal of $294 million of mark to market for contracts that settled
 in 2002.

        The  following  tables  analyze  the  changes in fair  values of trading
assets  and  liabilities.  The first  table  "Net Fair  Value of Energy  Trading
Contracts  and  Related  Derivatives"  shows  how the net fair  value of  energy
trading  contracts  was derived from the amounts  included in the balance  sheet
line item "energy  trading and  derivative  contracts."  The next table  "Energy
Trading Contracts and Related Derivatives" disaggregates realized and unrealized
changes in fair value;  identifies  changes in fair value as a result of changes
in valuation methodologies;  and reconciles the net fair value of energy trading
contracts and related  derivatives  at December 31, 2001 of $448 million to June
30, 2002 of $187 million.  Contracts  realized/settled during the period include
both sales and purchase  contracts.  The third table  "Energy  Trading  Contract
Maturities"  shows exposures to changes in fair values and  realization  periods
over time for each method used to determine fair value.

Net Fair Value of Energy Trading Contracts and Related Derivatives
                                                 June 30,       December 31,
                                              ---------------   ------------
                                                      2002            2001
                                                      ----            ----
                                              (in millions)    (in millions)
Energy Trading and Derivative Contracts:
    Current Asset                                   $ 9,466          $ 8,572
    Long-term Asset                                   3,672            2,370
    Current Liability                                (9,538)          (8,311)
    Long-term Liability                              (3,444)          (2,183)
                                                    -------          -------
Net Fair Value of Energy Trading Contracts and
 Derivative Contracts                                   156              448
Less non-trading related derivatives                    (31)             -
                                                    -------          -------
Net Fair Value of Energy Trading Contracts and
 Related Derivatives                                $   187          $   448
                                                    =======          =======
<PAGE>
The above net fair value of energy  trading  contracts  and related  derivatives
includes $47 million, at June 30, 2002, in unrealized  mark-to-market gains that
are  recognized in the income  statement at June 30, 2002.  Also included in the
above net fair value of energy  trading  contracts and related  derivatives  are
option  premiums that are deferred  until the related  contracts  settle and the
portion of changes in fair  values of  electricity  trading  contracts  that are
deferred for ratemaking purposes.
<TABLE>
<CAPTION>
AEP Consolidated Energy Trading Contracts and Related Derivatives
(in millions)
                                                                               Total
<S>                                                                          <C>        <C>
Net Fair Value of Energy Trading Contracts and Related Derivatives
 at December 31, 2001                                                        $ 448

(Gain) Loss from Contracts realized/settled during period                     (367)     (a)

Adjustments to (gain) Loss for Contracts entered into and
 Settled during period                                                         108      (a)

Fair Value of new open contracts when entered into during the period            50      (b)

Net option premium payments                                                     21

Change In fair value due to Methodology Changes                                  1      (c)

Changes in market value of contracts                                           (74)     (d)
                                                                             -----
Net Fair Value of Energy Trading Contracts and Commodity Derivatives
 at June 30, 2002                                                            $ 187      (e)
                                                                             =====
</TABLE>
<PAGE>
(a)       (Gain) Loss from  Contracts  Realized or Otherwise  Settled During the
          Period"  include  realized  gains from energy  trading  contracts  and
          related  derivatives  that settled  during 2002 that were entered into
          prior to 2002, as well as during 2002. "Adjustments to gains or losses
          for Contracts  Entered into and Settled  During the Period"  discloses
          the realized  gains from settled  energy  trading  contracts that were
          both  entered  into and closed  within  2002 that are  included in the
          total gains of $367 million, but not included in the ending balance of
          open contracts.
(b)       The "Fair Value of New Open Contracts When Entered Into During Period"
          represents  the fair value of  long-term  contracts  entered into with
          customers  during  2002.  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 representative of the delivery location.
(c)       The Company changed the discount rate applied to its trading portfolio
          from BBB+ Utility to LIBOR in the second quarter which  increased fair
          value by $10 million. In addition, the Company changed its methodology
          in valuing a spread option model so as to more accurately  reflect the
          exercising of power  transactions at optimal prices which reduced fair
          value by $9 million.
(d)       "Change in market Value of Contracts" represents the fair value change
          in the trading portfolio due to market fluctuations during the current
          period.  Market  fluctuations are attributable to various factors such
          as supply/demand, weather, storage, etc.
(e)       The net change in the fair value of energy trading contracts for 2002
          that resulted in a decrease of $261 million ($187  million less $448
          million)  represents  the balance  sheet change.  The net
          mark-to-market gain on energy trading contracts of $47 million and net
          mark-to-market  gain on gas inventory positions of $40 million
          represent the impact on earnings  related to open trading  positions
          as of June 30, 2002. The difference is related primarily to settlement
          of prior period open energy trading contracts ($294 million decrease);
          regulatory  deferrals  of  certain  mark-to-market  gains  that were
          recorded  as  regulatory liabilities  and not  reflected  in the
          income  statement  for those  companies  that operate in regulated
          jurisdictions;  and  deferrals  of option  premiums  included in the
          above  analysis,  which do not have a mark-to-market income statement
          impact.
<PAGE>
<TABLE>
<CAPTION>
Energy Trading Contracts
(in thousands)
                                                      APCo            CPL           CSPCo
<S>                                               <C>             <C>            <C>
Net Fair Value of Energy Trading
 Contracts at December 31, 2001                   $ 75,701        $ 3,857        $ 48,449
(Gain) Loss from Contracts
 realized/settled during period                    (19,026)        (1,133)        (12,470)
Change in Fair Value Due To
 Methodology Changes                                   350             42             228
Adjustments to (gain) loss for
 Contracts entered into and settled
 during the period                                   7,419            761           4,848
Fair Value of new open Contracts
 when entered into during period                     9,031          1,897           5,901
Net option premium payments                            354           -                232
Changes in market value of Contracts                14,669         (5,498)         12,522
                                                  --------        -------        --------
Net Fair Value of Energy Trading
 Contracts at June 30, 2002                       $ 88,498        $   (74)       $ 59,710
                                                  ========        =======        ========
</TABLE>
<TABLE>
<CAPTION>
Energy Trading Contracts
(in thousands)
                                                       I&M            KPCo           OPCo
Net Fair Value of Energy Trading
<S>                                               <C>             <C>            <C>
 Contracts at December 31, 2001                   $ 61,345        $12,729        $ 65,446
(Gain) Loss from Contracts
 realized/settled during period                    (13,492)        (4,921)        (16,959)
Change in Fair Value Due To
 Methodology Changes                                   247             90             311
Adjustments to (gain) loss for
 Contracts entered into and settled
 During the period                                   5,246          1,915           6,593
Fair Value of new open Contracts
 when entered into during period                     6,385          2,331           8,025
Net option premium payments                            251             92             315
Changes in market value of Contracts                (1,014)         4,972          26,175
                                                   -------        -------        --------
Net Fair Value of Energy Trading
 Contracts at June 30, 2002                       $ 58,968        $17,208        $ 89,906
                                                  ========        =======        ========
</TABLE>
<TABLE>
<CAPTION>
Energy Trading Contracts
(in thousands)
                                                       PSO           SWEPCo           WTU
<S>                                               <C>             <C>            <C>
Net Fair Value of Energy Trading
 Contracts at December 31, 2001                   $ 2,434         $ 2,900        $   915
(Gain) Loss from Contracts
 realized/settled during the period                  (863)           (990)          (336)
Change in Fair Value Due To
 Methodology Changes                                   32              36             12
Adjustments to (gain) loss for
 Contracts Entered into and settled
 during period                                        579             665            226
Fair Value of new open Contracts
 when entered into during period                      605             694          2,246
Net option premium payments                          -               -              -
Changes in market value of Contracts               (7,178)         (8,239)        (1,013)
                                                  -------         -------        -------
Net Fair Value of Energy Trading
 Contracts at June 30, 2002                       $(4,391)        $(4,934)       $ 2,050
                                                  =======         =======        =======
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Energy Trading Contract Maturities
                                                             Fair Value of Contracts at June 30, 2002
                                                                             Maturities
                                                                            (in millions)
                                                                                                        Total
AEP Consolidated                               Less than                   4-5          In Excess       Fair
Source of Fair Value                           1 year        1-3 years     years        Of 5 years      Value
--------------------                           ------        ---------     -----        ----------      -----
<S>                                            <C>           <C>           <C>          <C>             <C>
Prices actively quoted (a)                     $(134)        $ 84          $ -          $ -             $(50)
Prices provided by other external
 Sources (b)                                      74          115            8            -              197
Prices based on models and other
 Valuation methods (c)                            (2)         (26)          40           28               40
                                               -----         ----          ---          ---             ----
Total                                          $ (62)        $173          $48          $28             $187
                                               =====         ====          ===          ===             ====
</TABLE>
<TABLE>
<CAPTION>
Energy Trading Contract Maturities
                                                             Fair Value of Contracts at June 30, 2002
                                                                             Maturities
                                                                            (in thousands)
                                                                                                        Total
                                               Less than                   4-5          In Excess       Fair
Source of Fair Value                           1 year        1-3 years     years        Of 5 years      Value
--------------------                           ------        ---------     -----        ----------      -----
<S>                                            <C>           <C>           <C>          <C>             <C>
APCo
Prices provided by other
 External Sources (b)                          $23,532       $14,422       $ 2,358      $ -             $40,312
Prices based on models and other
 Valuation methods (c)                           6,079        23,757         9,655       8,695           48,186
                                               -------       -------       -------      ------          -------
  Total                                        $29,611       $38,179       $12,013      $8,695          $88,498
                                               =======       =======       =======      ======          =======

CPL
Prices provided by other
 External Sources (b)                          $(2,458)      $  739        $121         $ -             $(1,598)
Prices based on models and other
 Valuation methods (c)                            (635)       1,218         495          446              1,524
                                               --------      ------        ----         ----            -------
  Total                                        $(3,093)      $1,957        $616         $446            $   (74)
                                               ========      ======        ====         ====            =======

CSP
Prices provided by other
 External Sources (b)                          $16,874       $ 9,423       $1,540       $ -             $27,837
Prices based on models and other
 Valuation methods (c)                           4,359        15,523        6,309        5,682           31,873
                                               -------       -------       ------       ------          -------
  Total                                        $21,233       $24,946       $7,849       $5,682          $59,710
                                               =======       =======       ======       ======          =======

KPCo
Prices provided by other
 External Sources (b)                          $1,599        $3,722        $  608       $ -             $ 5,929
Prices based on models and other
 Valuation methods (c)                            413         6,130         2,492        2,244           11,279
                                               ------        ------        ------       ------          -------
  Total                                        $2,012        $9,852        $3,100       $2,244          $17,208
                                               ======        ======        ======       ======          =======
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
I&M
<S>                                            <C>           <C>            <C>         <C>             <C>
Prices provided by other
 External Sources (b)                          $17,626       $ 9,009        $1,473      $ -             $28,108
Prices based on models and other
 Valuation methods (c)                           4,554        14,841         6,032       5,433           30,860
                                               -------       -------        ------      ------          -------
  Total                                        $22,180       $23,850        $7,505      $5,433          $58,968
                                               =======       =======        ======      ======          =======

OPCo
Prices provided by other
 External Sources (b)                          $27,625       $13,505       $ 2,208      $ -             $43,338
Prices based on models and other
 Valuation methods (c)                           7,137        22,246         9,042       8,143           46,568
                                               -------       -------       -------      ------          -------
  Total                                        $34,762       $35,751       $11,250      $8,143          $89,906
                                               =======       =======       =======      ======          =======

PSO
Prices provided by other
 External Sources (b)                          $(4,924)       $  442          $ 72        $ -           $(4,410)
Prices based on models and other
 Valuation methods (c)                          (1,272)          728           296         267               19
                                               --------       ------          ----        ----          -------
  Total                                        $(6,196)       $1,170          $368        $267          $(4,391)
                                               ========       ======          ====        ====          =======

SWEPCo
Prices provided by other
 External Sources (b)                          $(5,568)       $  507          $ 83        $ -           $(4,977)
Prices based on models and other
 Valuation methods (c)                          (1,438)          836           340         306               43
                                               --------       ------          ----        ----          -------
  Total                                        $(7,006)       $1,343          $423        $306          $(4,934)
                                               ========       ======          ====        ====          =======

WTU
Prices provided by other
 External Sources (b)                          $220           $  434          $ 71        $ -            $  725
Prices based on models and other
 Valuation methods (c)                           57              715           291         262            1,325
                                               ----           ------          ----        ----           ------
  Total                                        $277           $1,149          $362        $262           $2,050
                                               ====           ======          ====        ====           ======
</TABLE>
(a)       "Prices Actively Quoted" represents the Company's exchange traded
          natural gas futures.
(b)       "Prices Provided by Other External Sources" represents the Company's
          positions in natural gas, power, and coal at points where
          over-the-counter  broker quotes are available.  Some prices from
          external sources are quoted as strips (one bid/ask for Nov-Mar,
          Apr-Oct, etc). Such transactions have also been included in this
          category.
(c)       "Prices  Based on Models  and Other  Valuation  Methods"  contain  the
          following:  the value of the Company's  adjustments  for liquidity and
          counterparty credit exposure,  the value of contracts not quoted by an
          exchange or an over-the-counter  broker, the value of transactions for
          which an internally developed price curve was developed as a result of
          the long  dated  nature  of  certain  transactions,  and the  value of
          certain structured transactions.
<PAGE>

Item 4.  Submission of Matters to a Vote of Security Holders.
         ---------------------------------------------------

AEP

        The annual meeting of shareholders was held in Columbus,  Ohio, on April
23, 2002. The holders of shares entitled to vote at the meeting or their proxies
cast votes at the  meeting  with  respect to the  following  three  matters,  as
indicated below:

        1.     Election of  thirteen  directors  to hold  office  until the next
               annual meeting and until their successors are duly elected.  Each
               nominee  for  director  received  the  votes of  shareholders  as
               follows:
<TABLE>
<CAPTION>
                                                         Number of Shares                  Number of
                       Nominee                               Voted For                 Votes Withheld
<S>                                                          <C>                           <C>
               E. R. Brooks                                  201,037,003                   55,252,755
               Donald M. Carlton                             248,549,741                    7,740,017
               John P. DesBarres                             252,026,061                    4,263,697
               E. Linn Draper, Jr.                           249,765,263                    6,524,495
               Robert W. Fri                                 251,979,293                    4,310,465
               William R. Howell                             247,814,513                    8,475,245
               Lester A. Hudson, Jr.                         249,730,186                    6,559,572
               Leonard J. Kujawa                             251,840,096                    4,449,662
               Richard L. Sandor                             252,037,196                    4,252,562
               Thomas V. Shockley, III                       251,929,822                    4,359,936
               Donald G. Smith                               252,372,686                    3,917,072
               Linda Gillespie Stuntz                        251,968,011                    4,321,747
               Kathryn D. Sullivan                           249,653,889                    6,635,869
</TABLE>
        2.     Approve the  appointment  by the Board of Directors of Deloitte &
               Touche LLP as independent auditors of AEP for the year 2002. The
               proposal was approved by a vote of the shareholders as follows:

               Votes FOR                                     244,793,710
               Votes AGAINST                                   9,303,198
               Votes ABSTAINED                                 6,062,395
               Broker NON-VOTES*                                       0

        3.     Shareholder  proposal  submitted by Ronald  Marsico. The proposal
               was  disapproved by a vote of the  shareholders as follows:

               Votes FOR                                      14,495,798
               Votes AGAINST                                 192,849,019
               Votes ABSTAINED                                 6,062,395
               Broker NON-VOTES*                              42,882,546

               *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.
<PAGE>

APCo

        The  annual  meeting  of  stockholders  was held on April 23,  2002 at 1
Riverside Plaza, Columbus, Ohio. At the meeting,  13,499,500 votes were cast FOR
each of the following  seven persons for election as directors and there were no
votes  withheld and such  persons were elected  directors to hold office for one
year or until their successors are elected and qualify:

               E. Linn Draper, Jr.                    Thomas V. Shockley, III
               Henry W. Fayne                         Susan Tomasky
               Armando A. Pena                        Joseph H. Vipperman
               Robert P. Powers

CPL

        Pursuant  to action by written  consent in lieu of an annual  meeting of
the sole  shareholder  dated April 11, 2002,  the  following  seven persons were
elected  directors  to hold  office for one year or until their  successors  are
elected and qualify:

               E. Linn Draper, Jr.                    Thomas V. Shockley III
               Henry W. Fayne                         Susan Tomasky
               Armando A. Pena                        Joseph H. Vipperman
               Robert P. Powers

I&M

        Pursuant  to action by written  consent in lieu of an annual  meeting of
the sole shareholder  dated April 23, 2002, the following  thirteen persons were
elected  directors  to hold  office for one year or until their  successors  are
elected and qualify:

               Karl G. Boyd                           Robert P. Powers
               E. Linn Draper, Jr.                    John R. Sampson
               John E. Ehler                          Thomas V. Shockley, III
               Henry W. Fayne                         David B. Synowiec
               David L. Lahrman                       Susan Tomasky
               Marc E. Lewis                          Joseph H. Vipperman
               Susanne M. Moorman

OPCo

        The  annual  meeting  of  shareholders  was  held  on May 7,  2002  at 1
Riverside Plaza, Columbus, Ohio. At the meeting there were 27,952,473 votes cast
FOR:

1.       Each of the following seven persons for election as directors and there
         were no votes withheld and such persons were elected  directors to hold
         office for one year or until their successors are elected and qualify:
<PAGE>

               E. Linn Draper, Jr.                    Thomas V. Shockley, III
               Henry W. Fayne                         Susan Tomasky
               Armando A. Pena                        Joseph H. Vipperman
               Robert P. Powers

2.       Approval of  amendment  to Article  Second of the  Amended  Articles of
         Incorporation of OPCo providing that the principal office of OPCo is to
         be located at 1 Riverside Plaza,  Columbus,  Franklin County, Ohio, and
         there were no votes against, abstentions or broker non-votes.

SWEPCo

        Pursuant  to action by written  consent in lieu of an annual  meeting of
the sole  shareholder  dated April 10, 2002,  the  following  seven persons were
elected  directors  to hold  office for one year or until their  successors  are
elected and qualify:

               E. Linn Draper, Jr.                    Thomas V. Shockley III
               Henry W. Fayne                         Susan Tomasky
               Armando A. Pena                        Joseph H. Vipperman
               Robert P. Powers

Item 5.  Other Information.

        AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU

        Reference  is made to page 29 of the Annual  Report on Form 10-K for the
year ended  December 31, 2001 (2001 10-K) for a discussion of regional  haze. On
May 24, 2002,  the D.C.  Circuit  Court issued an opinion and order  vacating in
part and upholding in part the regional  haze rule.  The court held that Federal
EPA could not establish Best Available Retrofit Technology  standards for entire
groups  of  emission   sources  without  regard  to  improvement  in  visibility
attributable  to individual  source  controls.  Federal EPA has filed a petition
seeking rehearing by the entire D.C. Circuit Court.

        AEP

        Reference  is made  to  pages  31  through  33 of the  2001  10-K  for a
discussion of the Clean Water Act. On May 8, 2002,  the U.S.  District Court for
the Southern District of West Virginia issued an injunction prohibiting the U.S.
Army Corps of Engineers  from  issuing  permits  under  Section 404 of the Clean
Water Act for the primary  purpose of disposal of waste  mining  overburden  and
spoil.  On June 17, 2002,  the court denied a request for stay filed by the U.S.
Department  of Justice and  intervenor,  Kentucky  Coal  Association.  The court
clarified that the decision only applies to the Corps' Huntington District.  The
court also  advised  that the ruling does not apply to dredged  material  placed
back in the stream  but does apply to  activities  other than coal  mining  that
require Section 404 permits. The  intervenor-defendants  have filed an appeal to
the U.S.  Fourth  Circuit  Court of  Appeals  and the court  has set a  briefing
schedule.  The effect on permitting activities of certain AEP subsidiaries under
Section 404 cannot be predicted but could be significant.
<PAGE>
Item 6.  Exhibits and Reports on Form 8-K.

        (a)    Exhibits:

         OPCo

               Exhibit 3(d) -  Certificate  of Amendment to Amended  Articles of
               Incorporation of OPCo, dated June 3, 2002.

               Exhibit  3(e)  -  Composite  copy  of  the  Amended  Articles  of
               Incorporation of OPCo (amended as of June 3, 2002).

        AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU

               Exhibit 12 - Computation of Consolidated Ratio of Earnings to
               Fixed Charges.

        AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU

               Exhibit 99.1 - Certification of Chief Executive  Officer Pursuant
               to Section  1350 of  Chapter 63 of Title 18 of the United  States
               Code.

               Exhibit 99.2 - Certification of Chief Financial  Officer Pursuant
               to Section  1350 of  Chapter 63 of Title 18 of the United  States
               Code.

        (b)    Reports on Form 8-K:

        Company Reporting  Date of Report   Item Reported

        AEP                June 5, 2002     Item 5. Other Events and Regulation
                                            FD Disclosure



                                            Item 7. Financial Statements and
                                            Exhibits

        APCo               June 13, 2002    Item 5. Other Events and Regulation
                                            FD Disclosure



                                            Item 7. Financial Statements and
                                            Exhibits


        AEP                June 18, 2002    Item 5. Other Events and Regulation
                                            FD Disclosure
<PAGE>
        SWEPCo             June 20, 2002    Item 5. Other Events and Regulation
                                            FD Disclosure



                                            Item 7. Financial Statements and
                                            Exhibits


        KPCo               June 25, 2002    Item 5. Other Events and Regulation
                                            FD Disclosure



                                            Item 7. Financial Statements and
                                            Exhibits


        AEGCo, CPL, CSPCo, I&M, OPCo, PSO, and WTU

        No  reports on Form 8-K were filed  during  the  quarter  ended June 30,
2002.



<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  signatures  for each  undersigned
company  shall be deemed to relate  only to  matters  having  reference  to such
company and any subsidiaries thereof.

                                        AMERICAN ELECTRIC POWER COMPANY, INC.



      By: /s/Armando A. Pena        By:  /s/Joseph M. Buonaiuto
          -----------------------       ----------------------------
              Armando A. Pena           Joseph M. Buonaiuto
              Treasurer                 Controller and Chief Accounting Officer



                             AEP GENERATING COMPANY
                            APPALACHIAN POWER COMPANY
                         CENTRAL POWER AND LIGHT COMPANY
                         COLUMBUS SOUTHERN POWER COMPANY
                         INDIANA MICHIGAN POWER COMPANY
                             KENTUCKY POWER COMPANY
                               OHIO POWER COMPANY
                       PUBLIC SERVICE COMPANY OF OKLAHOMA
                       SOUTHWESTERN ELECTRIC POWER COMPANY
                          WEST TEXAS UTILITIES COMPANY



      By: /s/Armando A. Pena        By:  /s/Joseph M. Buonaiuto
          -----------------------       ----------------------------
              Armando A. Pena           Joseph M. Buonaiuto
              Vice President and        Controller and Chief Accounting Officer
              Treasurer


Date: August 13, 2002