UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                                    FORM 10-Q
              [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                  For The Quarterly Period Ended MARCH 31, 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 April 30, 2002 was 322,822,489.
<PAGE>
<TABLE>
<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                                    FORM 10-Q

                      For The Quarter Ended March 31, 2002
                                    CONTENTS

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

   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-6
                              Consolidated Financial Statements                                                     A-7 - A-11

                         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-11
<PAGE>


           Item 2.        Registrants' Combined Management Discussion and Analysis of
                                 Financial Condition, Contingencies  and Other Matters                              M-1 - M-7
           Item 3.        Quantitative and Qualitative Disclosures About Market Risk                                N-1 - N-8

       Part II.           OTHER INFORMATION
           Item 5.            Other Information                                                                     O-1
           Item 6.            Exhibits and Reports on Form 8-K                                                      O-1
                                     (a)  Exhibits
                                           Exhibit 12
                                     (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.
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        Other risks and unforeseen events.
<PAGE>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    FIRST QUARTER 2002 vs. FIRST QUARTER 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

        First  quarter  2002 net  income of $181  million or $0.56 per share was
down  32% from  last  year's  earnings  of $266  million  or  $0.83  per  share.
Unfavorable market conditions and the effect of a March 2001 gain on the sale of
the Frontera power plant caused the earnings decline.

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.
         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
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.
<PAGE>
         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.
         As stated above,  AEP records and reports upon  settlement  sales under
forward  trading  contracts  as revenues and  purchases  under  forward  trading
contracts  as purchased  energy  expense.  If settled  forward sale and purchase
contracts  were  reported on a net basis,  the amounts of revenues and purchased
energy expense reported would have been:
<PAGE>
<TABLE>
<CAPTION>
                                                             Three Months Ended March 31,
                                                              2002                         2001
                                                                     (in millions)
                                               Gross          Net          Gross          Net
                                               -----          ---          -----          ---
<S>                                           <C>           <C>           <C>             <C>
Revenues:
    Electricity Marketing and Trading         $ 8,524       $1,999        $ 9,272         $2,103
    Gas Marketing and Trading                   3,591          382          3,606            262
    Domestic Electricity Delivery                 798          798            789            789
    Other Investments                             501          501            568            568
                                              -------       ------        -------         ------
    Total                                     $13,414       $3,680        $14,235         $3,722
                                              =======       ======        =======         ======

                                               Gross         Net           Gross          Net
                                               -----         ---           -----          ---
Fuel and Purchased Energy Expense:
    Electricity Marketing and Trading         $ 7,289        $  764        $ 8,221         $1,052
    Gas Marketing and Trading                   3,673           464          3,538            194
    Other Investments                             345           345            343            343
                                              -------        ------        -------         ------
    Total                                     $11,307        $1,573        $12,102         $1,589
                                              =======        ======        =======         ======
</TABLE>

         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  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.
RESULTS OF OPERATIONS
        Net income for the first  quarter of 2002  decreased by $85 million from
last year's  results  due to the effects of the sale of Frontera  power plant in
the first  quarter of 2001 and strong  performance  last year from the wholesale
business  reflecting  market  conditions  that were more favorable than in 2002.
Lower  energy  demand  in the  first  quarter  of 2002  depressed  margins  from
wholesale electric and gas marketing and trading. In March 2001 we completed the
sale of Frontera, one of the generating plants required to be divested under the
FERC approved merger settlement  agreements.  The sale resulted in a $46 million
after tax gain.
                                              Increase (Decrease)
                                                   (in millions)             %
                                                                             -
Revenues:
    Electric Marketing and Trading                 $(748)                    (8)
    Gas Marketing and Trading                        (15)                     -
    Domestic Electricity Delivery                      9                      1
    Other Investments                                 (67)                  (12)
                                                      ---
                                                    $(821)                   (6)
                                                    =====
<PAGE>
        The  decline  in  revenues  is  mainly  due to a  decrease  in  electric
marketing and trading revenues.  The decrease was driven largely by a decline in
demand due to mild weather and the slow  recovery  from the economic  recession.
Heating degree days for the first quarter of 2002 were down 13.2 % from the same
quarter last year. Electricity sales to industrial customers decreased 7.1% from
the same period last year.  The increase in gas trading volume can be attributed
to the  acquisition  of Houston Pipe Line (HPL) and expansion of our gas trading
operations around the pipeline.  Revenues from other investments declined due to
a  decrease  in  SEEBOARD  revenues   resulting  from  regulator  imposed  price
reductions.
                                           Increase (Decrease)
                                           (in millions)             %
                                                                     -
Fuel and Purchased Energy Expense:
    Electric Marketing and Trading          $(932)                 (11)
    Gas Marketing and Trading                 135                    4
    Other Investments                           2                    1
                                                -
Total Fuel and Purchased Energy Expense      (795)                  (7)
Maintenance and Other Operation Expense        84                    9
Depreciation and Amortization Expense          23                    7
Taxes Other Than Income Taxes                  18                   11
                                               --

Total Operating Expenses                    $(670)                  (5)
                                            =====

        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 first  quarter of 2001.  Net
generation decreased 5% 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,  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 the
acquisition of HPL and expansion of gas trading activity around the pipeline.
        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 plus the expenses of MEMCO,  a barging line;
Quaker Coal; and two power plants in the UK, all recently  acquired  businesses.
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.
        Other  income  decreased  due to the gain from the sale of  Frontera  in
2001.
        Other  expenses  increased  due to a write off of  goodwill on Gas Power
Systems resulting from management's decision to exit the business (See Note 2).
<PAGE>
        The  decrease  in income  taxes 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.
        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>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED STATEMENTS OF INCOME
                     (in millions, except per-share amounts)
                                   (UNAUDITED)
                                                            Three Months Ended March 31,
                                                             2002                  2001
                                                             ----                  ----
<S>                                                        <C>                   <C>
REVENUES:
   Electricity Marketing and Trading                       $ 8,524               $ 9,272
   Gas Marketing and Trading                                 3,591                 3,606
   Domestic Electricity Delivery                               798                   789
   Other Investments                                           501                   568
                                                           -------               -------
               TOTAL REVENUES                               13,414                14,235
                                                           -------               -------
EXPENSES:
   Fuel and Purchased Energy:
     Electricity Marketing and Trading                       7,289                 8,221
     Gas Marketing and Trading                               3,673                 3,538
     Other Investments                                         345                   343
                                                           -------               -------
               TOTAL FUEL AND PURCHASED ENERGY              11,307                12,102
   Maintenance and Other Operation                           1,042                   958
   Depreciation and Amortization                               359                   336
   Taxes Other Than Income Taxes                               186                   168
                                                           -------               -------
               TOTAL OPERATING EXPENSES                     12,894                13,564
                                                           -------               -------

OPERATING INCOME                                               520                   671

OTHER INCOME                                                    17                    53

OTHER EXPENSES                                                  22                    19

LESS: INTEREST                                                 228                   266
         PREFERRED STOCK DIVIDEND REQUIREMENTS OF
           SUBSIDIARIES                                          2                     3
         MINORITY INTEREST IN FINANCE SUBSIDIARY                 9                  -
                                                           -------               -------
                                                               239                   269

INCOME BEFORE INCOME TAXES                                     276                   436

INCOME TAXES                                                    95                   170
                                                           -------               -------

NET INCOME                                                 $   181               $   266
                                                           =======               =======

AVERAGE NUMBER OF SHARES OUTSTANDING                           322                   322
                                                               ===                   ===

EARNINGS PER SHARE (Basic and Dilutive):                     $0.56                 $0.83
                                                             =====                 =====

CASH DIVIDENDS PAID PER SHARE                                $0.60                 $0.60
                                                             =====                 =====

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

                                                       March 31, 2002           December 31, 2001
                                                       --------------           -----------------
                                                                        (in millions)
<S>                                                          <C>                           <C>
ASSETS
------
CURRENT ASSETS:
    Cash and Cash Equivalents                                $   306                       $   333
    Accounts Receivable (net)                                  2,554                         1,882
    Fuel, Materials and Supplies                                 963                         1,066
    Energy Trading and Derivative Contracts                    9,327                         8,572
    Other                                                      1,130                           710
                                                             -------                       -------

       TOTAL CURRENT ASSETS                                   14,280                        12,563
                                                             -------                       -------

PROPERTY, PLANT AND EQUIPMENT:
   Electric:
     Production                                               17,483                        17,477
     Transmission                                              5,937                         5,879
     Distribution                                             11,431                        11,310
   Other (including gas, coal mining and
     nuclear fuel)                                             4,838                         4,941
   Construction Work in Progress                               1,179                         1,102
                                                             -------                       -------
       Total Property, Plant and Equipment                    40,868                        40,709
   Accumulated Depreciation and Amortization                  16,421                        16,166
                                                             -------                       -------

       NET PROPERTY, PLANT AND EQUIPMENT                      24,447                        24,543
                                                             -------                       -------

REGULATORY ASSETS                                              2,573                         3,162
                                                             -------                       -------

SECURITIZED TRANSITION ASSET                                     758                          -
                                                             -------                       -------

INVESTMENTS IN POWER, DISTRIBUTION AND
  COMMUNICATIONS PROJECTS                                        599                           677
                                                             -------                       -------

GOODWILL                                                       1,591                         1,546
                                                             -------                       -------

INTANGIBLE ASSETS                                                471                           441
                                                             -------                       -------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS              3,268                         2,370
                                                             -------                       -------

OTHER ASSETS                                                   2,166                         1,979
                                                             -------                       -------

          TOTAL                                              $50,153                       $47,281
                                                             =======                       =======

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

                                                             March 31, 2002           December 31, 2001
                                                             --------------           -----------------
                                                                            (in millions)
<S>                                                                 <C>                        <C>
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
  Accounts Payable                                                  $ 2,162                    $ 2,245
  Short-term Debt                                                     3,984                      4,025
  Long-term Debt Due Within One Year                                  1,231                      1,430
  Energy Trading And Derivative Contracts                             9,231                      8,311
  Other                                                               2,519                      2,088
                                                                    -------                    -------

       TOTAL CURRENT LIABILITIES                                     19,127                     18,099
                                                                    -------                    -------

LONG-TERM DEBT                                                       10,571                      9,753
                                                                    -------                    -------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                     3,066                      2,183
                                                                    -------                    -------

DEFERRED INCOME TAXES                                                 4,765                      4,823
                                                                    -------                    -------

DEFERRED INVESTMENT TAX CREDITS                                         482                        491
                                                                    -------                    -------

DEFERRED CREDITS AND REGULATORY LIABILITIES                           1,175                        948
                                                                    -------                    -------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2                                                 192                        194
                                                                    -------                    -------

OTHER NONCURRENT LIABILITIES                                          1,362                      1,334
                                                                    -------                    -------

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                             156                        156
                                                                    -------                    -------

COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
                                2002           2001
                                ----           ----
      Shares Authorized.. . 600,000,000     600,000,000
      Shares Issued. . . . .331,618,850     331,234,997
      (8,999,992 shares were held in treasury at
       March 31, 2002 and December 31, 2001)                          2,156                      2,153
  Paid-in Capital                                                     2,912                      2,906
  Accumulated Other Comprehensive Income (Loss)                        (170)                      (126)
  Retained Earnings                                                   3,288                      3,296
                                                                    -------                    -------

          TOTAL COMMON SHAREHOLDERS' EQUITY                           8,186                      8,229
                                                                    -------                    -------

              TOTAL                                                 $50,153                    $47,281
                                                                    =======                    =======

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                   Three Months Ended March 31,
                                                                    2002                   2001
                                                                    ----                   ----
                                                                         (in millions)
<S>                                                                <C>                   <C>
OPERATING ACTIVITIES:
   Net Income                                                      $ 181                 $ 266
   Adjustments for Noncash Items:
      Depreciation and Amortization                                  362                   352
      Deferred Federal Income Taxes                                  (63)                   68
      Deferred Investment Tax Credits                                 (9)                   (9)
      Net Mark to Market Adjustment of Energy Trading Contracts      219                   (57)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                     (832)                  615
      Fuel, Materials and Supplies                                   100                   (13)
      Accrued Utility Revenues                                       (55)                   39
      Prepayments and Other                                          (58)                  (68)
      Accounts Payable                                                20                  (499)
      Taxes Accrued                                                    8                    15
      Interest Accrued                                               106                    65
      Rent Accrued - Rockport Plant Unit 2                            37                    37
   Option Premiums                                                    52                   156
   Change in Other Assets                                           (339)                 (378)
   Change in Other Liabilities                                       257                    (5)
                                                                   -----                 -----
          Net Cash Flows From Operating Activities                   (14)                  584
                                                                   -----                 -----

INVESTING ACTIVITIES:
  Construction Expenditures                                         (353)                 (315)
  Other                                                              (25)                  109
                                                                   -----                 -----
          Net Cash Flows Used For Investing Activities              (378)                 (206)
                                                                   -----                 -----

FINANCING ACTIVITIES:
  Issuance of Common Stock                                            14                     3
  Issuance of Long-term Debt                                         914                   132
  Change in Short-term Debt (net)                                    (41)                 (266)
  Retirement of Long-term Debt                                      (313)                 (209)
  Dividends Paid on Common Stock                                    (193)                 (193)
                                                                   -----                 -----
            Net Cash Flows Used For Financing Activities             381                  (533)
                                                                   -----                 -----

Effect of Exchange Rate Change on Cash                               (16)                   (7)
                                                                   -----                 -----

Net Decrease in Cash and Cash Equivalents                            (27)                 (162)
Cash and Cash Equivalents at Beginning of Period                     333                   437
                                                                   -----                 -----
Cash and Cash Equivalents at End of Period                         $ 306                 $ 275
                                                                   =====                 =====

Supplemental Disclosure:
Cash paid for  interest  net of  capitalized  amounts was $126  million and $115
million and for income  taxes was $94 million and $178 million in 2002 and 2001,
respectively.  Noncash  acquisitions  under capital leases were none in 2002 and
$19 million in 2001, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
                                   (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                                   4                                                  4
Common Stock Dividends                                                    (193)                            (193)
Other                                                     (5)                                                (5)
                                                                                                         ------
                                                                                                          7,860
Comprehensive Income:
  Other Comprehensive Income,
   Net of Taxes
     Currency Translation Adjustment                                                       (82)             (82)
     Unrealized Gain on Securities                                                          13               13
  Net Income                                                               266                              266
                                                                                                         ------
     Total Comprehensive Income                                                                             197
                                        ------        ------            ------           -----           ------

MARCH 31, 2001                          $2,152        $2,914            $3,163           $(172)          $8,057
                                        ======        ======            ======           =====           ======



JANUARY 1, 2002                         $2,153        $2,906            $3,296           $(126)          $8,229
Issuance of Common Stock                     3                                                                3
Common Stock Dividends                                                    (193)                            (193)
Other                                                      6                 4                               10
                                                                                                         ------
                                                                                                          8,049
Comprehensive Income:
  Other Comprehensive Income,
   Net of Taxes
    Currency Translation Adjustment                                                         (6)              (6)
    Unrealized Loss on Cash Flow
      Hedges                                                                               (38)             (38)
   Net Income                                                              181                              181
                                                                                                         ------
     Total Comprehensive Income                                                                             137
                                        ------        ------            ------            -----          ------

MARCH 31, 2002                          $2,156        $2,912            $3,288           $(170)          $8,186
                                        ======        ======            ======           =====           ======

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

                    FIRST QUARTER 2002 vs. FIRST QUARTER 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 $87,000 for the first quarter.
        A decrease in operating revenues of $10,632,000 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 2002 decreased the Rockport Plant's generation by 32%.
        Operating expenses declined 18% as follows:
                                          Increase (Decrease)
                                          -------------------
                                          (in thousands)         %
                                          --------------         -

Fuel                                         $(10,145)         (37)
Rent - Rockport Plant
  Unit 2                                         -               -
Other Operation                                   264            9
Maintenance                                     1,050           55
Depreciation                                       47            1
Taxes Other Than Income
  Taxes                                            10            1
Income Taxes                                   (1,818)         (74)
                                             --------
    Total                                    $(10,592)         (18)
                                             ========

        Fuel expense decreased due to the decline in generation.
        The increase in other  operation  expense is  primarily  due to higher
costs for employee benefits and property  insurance.
        Maintenance  expense  increased due to planned  outages in 2002.
        The decrease in income taxes  attributable  to operations is primarily
due to an over-accrual of state income taxes based on an estimate of higher
taxable income for the year 2001 than actually occurred.  The over-accrual was
adjusted later in 2001.
<PAGE>
<TABLE>
<CAPTION>
                             AEP GENERATING COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                                  Three Months Ended March 31,
                                                                     2002                  2001
                                                                     ----                  ----
                                                                          (in thousands)

<S>                                                               <C>                  <C>
OPERATING REVENUES - Sales to AEP Affiliates                      $49,875              $60,507
                                                                  -------              -------
OPERATING EXPENSES:
   Fuel                                                            17,500               27,645
   Rent - Rockport Plant Unit 2                                    17,071               17,071
   Other Operation                                                  3,222                2,958
   Maintenance                                                      2,976                1,926
   Depreciation                                                     5,633                5,586
   Taxes Other Than Income Taxes                                    1,053                1,043
   Income Taxes                                                       653                2,471
                                                                  -------              -------

           TOTAL OPERATING EXPENSES                                48,108               58,700
                                                                  -------              -------

OPERATING INCOME                                                    1,767                1,807

NONOPERATING INCOME                                                     2                 -

NONOPERATING EXPENSES                                                  12                    9

NONOPERATING INCOME TAX CREDITS                                       832                  871

INTEREST CHARGES                                                      696                  689
                                                                  -------              -------

NET INCOME                                                        $ 1,893              $ 1,980
                                                                  =======              =======
</TABLE>
<TABLE>
<CAPTION>
                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                                                  Three Months Ended March 31,
                                                                   2002                   2001
                                                                   ----                   ----
                                                                              (in thousands)

<S>                                                               <C>                  <C>
BALANCE AT BEGINNING OF PERIOD                                    $13,761              $ 9,722

NET INCOME                                                          1,893                1,980

CASH DIVIDENDS DECLARED                                             1,050                  959
                                                                  -------              -------

BALANCE AT END OF PERIOD                                          $14,604              $10,743
                                                                  =======              =======

The common stock of AEGCo is wholly owned by AEP.

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

                                                  March 31, 2002            December 31, 2001
                                                  --------------            -----------------
                                                              (in thousands)
<S>                                                       <C>                         <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                             $639,544                    $638,297
   General                                                   3,012                       3,012
   Construction Work in Progress                             9,649                       6,945
                                                          --------                    --------
        Total Electric Utility Plant                       652,205                     648,254
   Accumulated Depreciation                                342,515                     337,151
                                                          --------                    --------
           NET ELECTRIC UTILITY PLANT                      309,690                     311,103
                                                          --------                    --------

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

CURRENT ASSETS:
   Cash and Cash Equivalents                                 4,212                         983
   Accounts Receivable:
      Affiliated Companies                                  21,007                      22,344
      Miscellaneous                                            147                         147
   Fuel - at average cost                                   16,555                      15,243
   Materials and Supplies - at average cost                  4,382                       4,480
   Prepayments                                                 128                         244
                                                          --------                    --------
           TOTAL CURRENT ASSETS                             46,431                      43,441
                                                          --------                    --------

REGULATORY ASSETS                                            5,149                       5,207
                                                          --------                    --------

DEFERRED CHARGES                                             3,816                       1,471
                                                          --------                    --------

           TOTAL ASSETS                                   $365,205                    $361,341
                                                          ========                    ========

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

                                                   March 31, 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                                       14,604                    13,761
                                                         --------                  --------
      Total Common Shareholder's Equity                    39,038                    38,195
   Long-term Debt                                          44,795                    44,793
                                                         --------                  --------

        TOTAL CAPITALIZATION                               83,833                    82,988
                                                         --------                  --------

OTHER NONCURRENT LIABILITIES                                   74                        76
                                                         --------                  --------

CURRENT LIABILITIES:
   Advances from Affiliates                                16,538                    32,049
   Accounts Payable:
      General                                               4,241                     7,582
      Affiliated Companies                                  3,774                     1,654
   Taxes Accrued                                           10,306                     4,777
   Rent Accrued - Rockport Plant Unit 2                    23,427                     4,963
   Other                                                    2,938                     3,481
                                                         --------                  --------
        TOTAL CURRENT LIABILITIES                          61,224                    54,506
                                                         --------                  --------

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
 PLANT UNIT 2                                             115,225                   116,617
                                                         --------                  --------

REGULATORY LIABILITIES:
   Deferred Investment Tax Credit                          55,469                    56,304
   Amounts Due to Customers for Income Taxes               22,059                    22,725
                                                         --------                  --------
        TOTAL REGULATORY LIABILITIES                       77,528                    79,029
                                                         --------                  --------

DEFERRED INCOME TAXES                                      27,171                    27,975
                                                         --------                  --------

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

CONTINGENCIES (Note 8)

        TOTAL CAPITALIZATION AND LIABILITIES             $365,205                  $361,341
                                                         ========                  ========

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

                                                                Three Months Ended March 31,
                                                                 2002                   2001
                                                                 ----                   ----
                                                                        (in thousands)
<S>                                                          <C>                     <C>
OPERATING ACTIVITIES:
   Net Income                                                $  1,893                $  1,980
   Adjustment for Noncash Items:
     Depreciation                                               5,633                   5,586
     Deferred Federal Income Taxes                             (1,470)                 (1,462)
     Deferred Investment Tax Credits                             (835)                   (837)
     Amortization of Deferred Gain on Sale and Leaseback -
       Rockport Plant Unit 2                                   (1,392)                 (1,392)
     Deferred Property Taxes                                   (2,693)                 (2,737)
   Changes in Certain Current Assets and Liabilities:
     Accounts Receivable                                        1,337                     500
     Fuel, Materials and Supplies                              (1,214)                    661
     Accounts Payable                                          (1,221)                  3,783
     Taxes Accrued                                              5,529                   6,131
     Rent Accrued - Rockport Plant Unit 2                      18,464                  18,464
   Change in Other Assets                                         586                     199
   Change in Other Liabilities                                   (545)                    375
                                                             --------                --------

           Net Cash Flow From Operating Activities             24,072                  31,251
                                                             --------                --------

INVESTING ACTIVITIES - Construction Expenditures               (4,282)                   (432)
                                                             --------                --------

FINANCING ACTIVITIES:
     Change in Advances from Affiliates (net)                 (15,511)                (27,849)
     Dividends Paid                                            (1,050)                   (959)
                                                             --------                --------
           Net Cash Flows Used For Financing Activities       (16,561)                (28,808)
                                                             --------                --------

Net Increase in Cash and Cash Equivalents                       3,229                   2,011
Cash and Cash Equivalents at Beginning of Period                  983                   2,757
                                                             --------                --------
Cash and Cash Equivalents at End of Period                   $  4,212                $  4,768
                                                             ========                ========

Supplemental Disclosure:
Cash paid for interest net of  capitalized  amounts was  $1,108,000 and $644,000
and for income taxes was $176,000 and $1,349,000 in 2002 and 2001, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                    FIRST QUARTER 2002 vs. FIRST QUARTER 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>
        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  APCo 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  $6.4  million or 10% mainly due to the effect of
strong  performance  in  2001  by  the  wholesale  business   reflecting  market
conditions that were more favorable than in 2002.  Lower  electricity  demand in
the first quarter of 2002 depressed  margins from wholesale  electric  marketing
and trading. 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.
<PAGE>
        The following analyzes the changes in operating revenues:
                                    Increase (Decrease)
                                     (in millions)          %

         Electricity Marketing             $(517)         (29)
          and Trading*
         Energy Delivery*                      3            2
         Sales to AEP Affiliates              (5)         (11)
                                           -----
              Total                        $(519)         (26)
                                           =====

         *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  margins caused by
decreased  electricity  demand  driven  largely  by mild  weather  and the  slow
recovery  from the economic  recession.  Sales to AEP  affiliates  declined as a
result of the mild weather and  economic  conditions  that  reduced  electricity
sales.
        Operating expenses declined 27% in 2002.  The changes in the components
of operating expenses were:
                                           Increase (Decrease)
                                           -------------------
                                           (in millions)             %
                                           -------------             -

         Fuel                                      $  12            13
         Electricity Marketing and
           Trading Purchases                        (474)          (32)
         Purchases from AEP Affiliates               (45)          (42)
         Other Operation                               2             2
         Maintenance                                  (7)          (22)
         Depreciation and Amortization                 3             7
         Taxes Other Than Income Taxes                 -             -
         Income Taxes                                 (3)           (7)
                                                   -----
              Total                                $(512)          (27)
                                                   =====

        Fuel  expense  increased  due to an increase in electric  generation  as
certain plants that had undergone boiler plant  maintenance in the first quarter
of 2001 were available for service in the first quarter of 2002.
        The decline in  electricity  marketing and trading  purchases was mainly
due to reduced prices caused by decreased  electricity  demand driven largely by
mild weather and the economic recession.
        The decrease in maintenance expense is due to the effect of boiler plant
maintenance performed on certain plants in the first quarter of 2001.
        Depreciation  and amortization  expense  increased 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 5 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.
<PAGE>
        The  decrease in income taxes from  operations  was due to a decrease 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
decreased  electricity  demand resulting from mild weather and the slow recovery
from the economic recession.
        Interest  charges  decreased due primarily to increased  allowances  for
borrowed  funds as a  result  of  increased  construction  expenditures  and the
retirement of first mortgage bonds on March 1, 2001 and the retirement of senior
unsecured notes in June 2001.
<PAGE>
                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                  Three Months Ended March 31,
                                                    2002                  2001
                                                    ----                  ----
                                                            (in thousands)
OPERATING REVENUES:
    Electricity Marketing and Trading         $1,257,355              $1,773,894
    Energy Delivery                              154,995                 152,097
    Sales to AEP Affiliates                       42,806                  48,136
                                              ----------              ----------
           TOTAL OPERATING REVENUES            1,455,156               1,974,127
                                              ----------              ----------

OPERATING EXPENSES:
   Fuel                                          107,490                  95,476
   Purchased Power:
      Electricity Marketing and Trading        1,005,599               1,479,528
      AEP Affiliates                              60,780                 105,674
   Other Operation                                67,427                  65,889
   Maintenance                                    25,851                  33,009
   Depreciation and Amortization                  46,772                  43,717
   Taxes Other Than Income Taxes                  24,995                  25,428
   Income Taxes                                   34,688                  37,254
                                              ----------              ----------
           TOTAL OPERATING EXPENSES            1,373,602               1,885,975
                                              ----------              ----------

OPERATING INCOME                                  81,554                  88,152

NONOPERATING INCOME                              400,172                 465,405

NONOPERATING EXPENSES                            398,733                 458,205

NONOPERATING INCOME TAX EXPENSE                      264                   2,149

INTEREST CHARGES                                  27,388                  31,416
                                              ----------              ----------

NET INCOME                                        55,341                  61,787

PREFERRED STOCK DIVIDEND REQUIREMENTS                503                     503
                                              ----------              ----------

EARNINGS APPLICABLE TO COMMON STOCK           $   54,838              $   61,284
                                              ==========              ==========

                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                              Three Months Ended March 31,
                                               2002                  2001
                                               ----                  ----
                                                        (in thousands)

NET INCOME                                 $55,341                $61,787

OTHER COMPREHENSIVE INCOME (LOSS)
    Foreign Currency Exchange Rate Hedge       143                   (417)
                                           -------                -------

COMPREHENSIVE INCOME                       $55,484                $61,370
                                           =======                =======

The common stock of the Company is wholly owned by AEP.

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

                                               Three Months Ended March 31,
                                            2002                       2001
                                            ----                       ----
                                                     (in thousands)

BALANCE AT BEGINNING OF PERIOD          $150,797                     $120,584

NET INCOME                                55,341                       61,787

DEDUCTIONS:
  Cash Dividends Declared:
        Common Stock                      30,984                       32,399
        Cumulative Preferred Stock           361                          361
  Capital Stock Expense                      142                          142
                                        --------                     --------

BALANCE AT END OF PERIOD                $174,651                     $149,469
                                        ========                     ========

The common stock of the Company is wholly owned by AEP.

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

                                            March 31, 2002  December 31, 2001
                                            --------------  -----------------
                                                     (in thousands)
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                   $2,084,311       $2,093,532
   Transmission                                  1,212,470        1,222,226
   Distribution                                  1,889,828        1,887,020
   General                                         260,110          257,957
   Construction Work in Progress                   267,720          203,922
                                                ----------       ----------
        Total Electric Utility Plant             5,714,439        5,664,657
   Accumulated Depreciation and Amortization     2,326,515        2,296,481
                                                ----------       ----------
        NET ELECTRIC UTILITY PLANT               3,387,924        3,368,176
                                                ----------       ----------

OTHER PROPERTY AND INVESTMENTS                      51,497           53,736
                                                ----------       ----------

LONG-TERM ENERGY TRADING CONTRACTS                 521,221          316,249
                                                ----------       ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                          -              13,663
   Accounts Receivable:
      Customers                                    120,599          113,371
      Affiliated Companies                          98,805           63,368
      Miscellaneous                                 20,983           11,847
      Allowance for Uncollectible Accounts          (2,259)          (1,877)
   Fuel - at average cost                           50,582           56,699
   Materials and Supplies - at average cost         53,307           59,849
   Accrued Utility Revenues                         23,894           30,907
   Energy Trading Contracts                        766,378          566,284
   Prepayments                                      21,694           16,018
                                                ----------       ----------
        TOTAL CURRENT ASSETS                     1,153,983          930,129
                                                ----------       ----------

REGULATORY ASSETS                                  391,518          397,383
                                                ----------       ----------

DEFERRED CHARGES                                    45,939           42,265
                                                ----------       ----------

        TOTAL ASSETS                            $5,552,082       $5,107,938
                                                ==========       ==========

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


                                                March 31, 2002      December 31, 2001
                                                 -------------      -----------------
                                                            (in thousands)
<S>                 <C>                              <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                                      715,928                 715,786
   Accumulated Other Comprehensive Income (Loss)           (197)                   (340)
   Retained Earnings                                    174,651                 150,797
                                                     ----------              ----------
        Total Common Shareowner's Equity              1,150,840               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                                     1,476,819               1,476,552
                                                     ----------              ----------

           TOTAL CAPITALIZATION                       2,656,309               2,631,903
                                                     ----------              ----------

OTHER NONCURRENT LIABILITIES                             84,672                  84,104
                                                     ----------              ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                    80,007                  80,007
   Advances from Affiliates                             259,826                 291,817
   Accounts Payable - General                           100,440                 131,387
   Accounts Payable - Affiliated Companies              126,921                  84,518
   Taxes Accrued                                         84,712                  55,583
   Customer Deposits                                     14,874                  13,177
   Interest Accrued                                      39,286                  21,770
   Energy Trading Contracts                             740,311                 549,703
   Other                                                 71,916                  75,299
                                                     ----------              ----------

           TOTAL CURRENT LIABILITIES                  1,518,293               1,303,261
                                                     ----------              ----------

DEFERRED INCOME TAXES                                   700,120                 703,575
                                                     ----------              ----------

DEFERRED INVESTMENT TAX CREDITS                          37,230                  38,328
                                                     ----------              ----------

LONG-TERM ENERGY TRADING CONTRACTS                      463,896                 257,129
                                                     ----------              ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS              91,562                  89,638
                                                     ----------              ----------

CONTINGENCIES (Note 8)

        TOTAL CAPITALIZATION AND LIABILITIES         $5,552,082              $5,107,938
                                                     ==========              ==========

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

                                                              Three Months Ended March 31,
                                                                2002                    2001
                                                                ----                    ----
                                                                    (in thousands)
<S>                                                        <C>                       <C>
OPERATING ACTIVITIES:
   Net Income                                              $  55,341                 $  61,787
   Adjustments for Noncash Items:
      Depreciation and Amortization                           46,800                    43,745
      Deferred Federal Income Taxes                           (3,644)                   19,438
      Deferred Investment Tax Credits                         (1,098)                   (1,106)
      Deferred Power Supply Costs (net)                          352                       121
      Mark to Market of Energy Trading Contracts              (6,653)                  (59,398)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                              (51,419)                   82,071
      Fuel, Materials and Supplies                            12,659                     3,091
      Accrued Utility Revenues                                 7,013                    51,292
      Accounts Payable                                        11,456                     6,086
      Taxes Accrued                                           29,129                     5,417
      Interest Accrued                                        17,516                    17,618
   Change in Other Assets                                     (7,043)                  (16,226)
   Change in Other Liabilities                                 1,366                    (2,789)
                                                           ---------                 ---------
           Net Cash Flows From Operating Activities          111,775                   211,147
                                                           ---------                 ---------

INVESTING ACTIVITIES:
      Construction Expenditures                              (62,685)                  (39,922)
      Proceeds from Sale of Property                             583                     1,182
                                                           ---------                 ---------
           Net Cash Flows Used For Investing Activities      (62,102)                  (38,740)
                                                           ---------                 ---------

FINANCING ACTIVITIES:
      Change in Short-term Debt (net)                           -                     (191,495)
      Change in Advances From Affiliates                     (31,991)                  153,572
      Retirement of Long-term Debt                              -                     (100,000)
      Dividends Paid on Common Stock                         (30,984)                  (32,399)
      Dividends Paid on Cumulative Preferred Stock              (361)                     (361)
                                                           ---------                 ---------
           Net Cash Flows Used For Financing Activities      (63,336)                 (170,683)
                                                           ---------                 ---------

Net Increase (Decrease) in Cash and Cash Equivalents         (13,663)                    1,724
Cash and Cash Equivalents at Beginning of Period              13,663                     5,847
                                                           ---------                 ---------
Cash and Cash Equivalents at End of Period                 $    -                    $   7,571
                                                           =========                 =========

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $9,222,000 and $13,156,000
and  for  income  taxes  was  $9,593,000  and  $13,543,000  in  2002  and  2001,
respectively. Noncash acquisitions under capital leases were $-0- and $1,512,000
in 2002 and 2001, respectively.

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

                    FIRST QUARTER 2002 vs. FIRST QUARTER 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 shares in the revenues and costs of 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.
         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 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.
        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.
<PAGE>
        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  CPL to market risk.  See  "Quantitative  and
Qualitative  Disclosure  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  $10.6  million,  or 30%,  primarily  due to mild
winter  weather  and a slow  recovery  from the  economic  recession.  Operating
revenues decreased $200 million for the quarter as shown below:
                                      Increase (Decrease)
                                            (in millions)     %

         Electricity Marketing
          and Trading*                       $(361)         (76)
         Energy Delivery*                        2            2
         Sales to AEP Affiliates               159          N.M.
                                             -----
              Total                          $(200)         (33)
                                             =====

         *Reflects  the  allocation  of certain  transmission  and  distribution
         revenues included in bundled retail rates to energy delivery.

         N.M. = Not Meaningful
<PAGE>
     Electricity  marketing  and trading  revenues  decreased  $361 million as a
result of several  factors,  including  the  elimination  of retail sales in the
ERCOT area as of January 1, 2002, a decrease in energy trading,  and mild winter
weather.
     The  significant  increase  in  Sales  to  AEP  Affiliates  is  due  to the
introduction on January 1, 2002 of customer choice of electricity supplier which
resulted in CPL selling power at wholesale to a new  affiliated  REP.
     Operating  expenses  declined 36% in 2002. The changes in the components of
operating expenses were:
                                          Increase (Decrease)
                                          -------------------
                                          (in millions)             %
                                          -------------             -

         Fuel                                     $ (98)           (64)
         Electricity Marketing and
           Trading Purchases                        (73)           (36)
         Purchases from AEP Affiliates               (5)           (38)
         Other Operation                             (9)           (12)
         Maintenance                                 (6)           (37)
         Depreciation and Amortization                -              -
         Taxes Other Than Income Taxes                8             43
         Income Taxes                                (8)           (44)
                                                  -----
              Total                               $(191)           (36)
                                                  =====

         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 due to the slow economic  recovery and the mild winter
weather.
         The decrease in maintenance and other operation  expenses resulted from
the effects of a STP nuclear refueling outage in 2001.
         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>
                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)
                                             Three Months Ended March 31,
                                                2002                 2001
                                                ----                 ----
                                                   (in thousands)
OPERATING REVENUES:
Electric Marketing and Trading              $111,435             $472,294
Energy Delivery                              112,127              110,330
Sales to Affiliates                          179,661               20,788
                                            --------             --------
           Total Operating Revenues          403,223              603,412
                                            --------             --------

OPERATING EXPENSES:
   Fuel                                       54,328              151,853
   Purchased Power:
   Electric Marketing and Trading            128,325              201,796
   Affiliates                                  7,927               12,770
   Other Operation                            65,986               75,071
   Maintenance                                10,959               17,287
   Depreciation and Amortization              41,847               42,391
   Taxes Other Than Income Taxes              27,922               19,488
   Income Taxes                               10,484               18,604
                                            --------             --------
           TOTAL OPERATING EXPENSES          347,778              539,260
                                            --------             --------

OPERATING INCOME                              55,445               64,152

NONOPERATING INCOME                            9,531                3,199

NONOPERATING EXPENSES                          9,387                  837

NONOPERATING INCOME TAX EXPENSE                  133                  723

INTEREST CHARGES                              31,011               30,760
                                            --------             --------

NET INCOME                                    24,445               35,031

PREFERRED STOCK DIVIDEND REQUIREMENTS             60                   60
                                            --------             --------

EARNINGS APPLICABLE TO COMMON STOCK         $ 24,385             $ 34,971
                                            ========             ========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                          Three Months Ended March 31,
                                           2002                     2001
                                           ----                     ----
                                                   (in thousands)
BALANCE AT BEGINNING OF PERIOD           $826,197                $792,219
NET INCOME                                 24,445                  35,031
DEDUCTIONS:
  Cash Dividends Declared:
     Common Stock                          38,502                  37,014
     Preferred Stock                           60                      60
Other                                        -                          1
                                         --------                --------
BALANCE AT END OF PERIOD                 $812,080                $790,175
                                         ========                ========

The common stock of the Company 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 BALANCE SHEETS
                                   (UNAUDITED)

                                                 March 31, 2002           December 31, 2001
                                                 --------------           -----------------
                                                                 (in thousands)
<S>                                                   <C>                         <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                         $3,171,938                  $3,169,421
   Transmission                                          693,317                     663,655
   Distribution                                        1,294,074                   1,279,037
   General                                               244,361                     241,137
   Construction Work in Progress                         134,133                     169,075
   Nuclear Fuel                                          247,393                     247,382
                                                      ----------                  ----------
        Total Electric Utility Plant                   5,785,216                   5,769,707
   Accumulated Depreciation and Amortization           2,476,402                   2,446,027
                                                      ----------                  ----------
      NET ELECTRIC UTILITY PLANT                       3,308,814                   3,323,680
                                                      ----------                  ----------

OTHER PROPERTY AND INVESTMENTS                            48,989                      47,950
                                                      ----------                  ----------

SECURITIZED TRANSITION ASSET                             758,436                        -
                                                      ----------                  ----------

LONG-TERM ENERGY TRADING CONTRACTS                        32,259                      72,502
                                                      ----------                  ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                               9,206                      10,909
   Accounts Receivable:
      General                                             52,545                      38,459
      Affiliated Companies                                61,588                       6,249
      Allowance for Uncollectable Accounts                  (211)                       (186)
   Fuel Inventory - at LIFO cost                          38,572                      38,690
   Materials and Supplies - at average cost               56,952                      55,475
   Energy Trading Contracts                               56,534                     212,979
   Prepayments and Other Current Assets                    6,967                       2,742
                                                      ----------                  ----------
      TOTAL CURRENT ASSETS                               282,153                     365,317
                                                      ----------                  ----------

REGULATORY ASSETS                                        227,140                     226,806
                                                      ----------                  ----------

REGULATORY ASSETS DESIGNATED FOR SECURITIZATION          179,384                     959,294
                                                      ----------                  ----------

NUCLEAR DECOMMISSIONING TRUST FUND                       100,763                      98,600
                                                      ----------                  ----------

DEFERRED CHARGES                                          83,596                      21,837
                                                      ----------                  ----------

     TOTAL ASSETS                                     $5,021,534                  $5,115,986
                                                      ==========                  ==========

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

                                                                    March 31, 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 March 31, 2002
                          6,755,535 Shares at December 31, 2001          $   55,292                  $  168,888
   Paid-in Capital                                                          132,592                     405,000
   Retained Earnings                                                        812,080                     826,197
                                                                         ----------                  ----------
        Total Common Shareowner's Equity                                    999,964                   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                                                         1,736,183                     988,768
                                                                         ----------                  ----------

           TOTAL CAPITALIZATION                                           2,878,364                   2,531,070
                                                                         ----------                  ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                       164,200                     265,000
   Advances from Affiliates                                                 238,830                     354,277
   Accounts Payable - General                                                37,545                      65,307
   Accounts Payable - Affiliated Companies                                   44,028                      49,301
   Customer Deposits                                                          2,204                      26,744
   Over Recovered Fuel                                                       58,956                      57,762
   Taxes Accrued                                                            101,279                      83,512
   Interest Accrued                                                          28,035                      18,524
   Energy Trading Contracts                                                  61,628                     219,486
   Other                                                                     16,278                      22,768
                                                                         ----------                  ----------

           TOTAL CURRENT LIABILITIES                                        752,983                   1,162,681
                                                                         ----------                  ----------

DEFERRED INCOME TAXES                                                     1,157,840                   1,163,795
                                                                         ----------                  ----------

DEFERRED INVESTMENT TAX CREDITS                                             121,591                     122,892
                                                                         ----------                  ----------

LONG-TERM ENERGY TRADING CONTRACTS                                           29,774                      62,138
                                                                         ----------                  ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                  80,982                      73,410
                                                                         ----------                  ----------

CONTINGENCIES (Note 8)

           TOTAL CAPITALIZATION AND LIABILITIES                          $5,021,534                  $5,115,986
                                                                         ==========                  ==========

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

                                                                           Three Months Ended March 31,
                                                                            2002                  2001
                                                                            ----                  ----
                                                                              (in thousands)
<S>                                                                   <C>                        <C>
OPERATING ACTIVITIES:
   Net Income                                                         $  24,445                  $ 35,031
   Adjustments for Noncash Items:
      Depreciation and Amortization                                      41,847                    42,391
      Deferred Income Taxes                                              (8,083)                    2,579
      Deferred Investment Tax Credits                                    (1,302)                   (1,302)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                         (69,400)                    8,203
      Fuel, Materials and Supplies                                       (1,359)                  (15,468)
      Fuel Recovery                                                       1,194                     2,073
      Electricity Mark to Market                                          6,466                    (9,260)
      Accounts Payable                                                  (33,035)                  (18,115)
      Taxes Accrued                                                      17,767                    27,571
   Deferred Property Taxes                                                 -                      (29,292)
   Change in Other Assets                                               (53,865)                  (43,099)
   Change in Other Liabilities                                          (11,978)                   22,934
                                                                      ---------                  --------
           Net Cash Flows From (Used For) Operating Activities          (87,303)                   24,246
                                                                      ---------                  --------

INVESTING ACTIVITIES:
      Construction Expenditures                                         (21,002)                  (38,873)
      Other                                                                -                         (354)
                                                                      ---------                  --------
           Net Cash Flows Used For Investing Activities                 (21,002)                  (39,227)
                                                                      ---------                  --------

FINANCING ACTIVITIES:
      Issuance of Long-term Debt                                        796,613                      -
      Retirement of Long-term Debt                                     (149,998)                     (505)
      Retirement of Common Stock                                       (386,004)                     -
      Change in Advances from Affiliates (net)                         (115,447)                   43,156
      Dividends Paid on Common Stock                                    (38,502)                  (37,014)
      Dividends Paid on Cumulative Preferred Stock                          (60)                      (60)
                                                                      ---------                  --------
           Net Cash Flows From Financing Activities                     106,602                     5,577
                                                                      ---------                  --------

Net Decrease in Cash and Cash Equivalents                                (1,703)                   (9,404)
Cash and Cash Equivalents at Beginning of Period                         10,909                    14,253
                                                                      ---------                  --------
Cash and Cash Equivalents at End of Period                            $   9,206                  $  4,849
                                                                      =========                  ========
</TABLE>
Supplemental Disclosure:
Cash  paid  for  interest  net  of  capitalized   amounts  was  $18,505,000  and
$24,938,000  and for income taxes was  $18,482,000  and  $6,071,000  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

                    FIRST QUARTER 2002 vs. FIRST QUARTER 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.

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.
<PAGE>
           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
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.
<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 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  decreased $3.8 million or 10% due to depressed  margins from
electric  marketing  and  trading  caused  by lower  energy  demand in the first
quarter of 2002. Earnings from electric marketing and trading were much stronger
in the first quarter of 2001 than in recent months due to milder weather and the
slow recovery from the economic recession.
        The  decline  in  revenues  is  mainly  due to a  decrease  in  electric
marketing and trading revenues.  The following analyzes the changes in operating
revenues:
                                    Increase (Decrease)
                                          (in millions)     %

         Electricity Marketing
          And Trading*                     $(168.7)        (17)
         Energy Delivery*                      3.6           4
         Sales to AEP Affiliates             (11.1)        (59)
                                           -------
              Total                        $(176.2)        (16)
                                           =======

         *Reflects  the  allocation  of certain  transmission  and  distribution
         revenues included in bundled retail rates to energy delivery.

        The decrease in electric  marketing and trading was driven  largely by a
decline in demand due to mild  winter  weather  and the slow  recovery  from the
economic recession.  Heating degree days for the first quarter of 2002 were down
11.8% from the same quarter last year. Electricity sales to industrial customers
decreased 4%.
        Operating expenses declined 16% in 2002.  The changes in the components
of operating expenses were:
                                         Increase (Decrease)
                                         -------------------
                                         (in millions)               %
                                         -------------               -

         Fuel                                     $  (1.4)          (3)
         Electricity Marketing and
           Trading Purchases                       (161.7)         (20)
         Purchases from AEP Affiliates               (0.7)          (1)
         Other Operation                             (0.4)          (1)
         Maintenance                                 (4.6)         (25)
         Depreciation and Amortization                1.3            4
         Taxes Other Than Income Taxes               (0.4)          (1)
         Income Taxes                                (5.8)         (25)
                                                  -------
              Total                               $(173.7)         (16)
                                                  =======

        The decrease in fuel expense was primarily  attributable  to a reduction
in generation of 4.6% due to the reduced demand for electricity.
        Electricity marketing and trading purchases also declined due to reduced
demand,  a continuation  of the market  conditions  that developed in the fourth
quarter of 2001.
        Maintenance  expenses  decreased  in the  first  quarter  of 2002 due to
boiler  overhaul  work that was  performed  during  the first  quarter  of 2001.
Expenses for maintaining  distribution overhead lines and underground lines were
also lower in 2002.
<PAGE>
        A decrease in pre-tax operating income caused income taxes  attributable
to operations to decline.
        The  increase  in  nonoperating  income  which  was  offset  by a larger
increase 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 reflecting milder
weather and the slow economic recovery.
        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>
                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                               Three Months Ended March 31,
                                               2002                    2001
                                               ----                    ----
                                                      (in thousands)
OPERATING REVENUES:
   Electricity Marketing and Trading      $  839,089               $1,007,831
   Energy Delivery                           102,548                   98,996
   Sales to AEP Affiliates                     7,678                   18,746
                                          ----------               ----------
           TOTAL OPERATING REVENUES          949,315                1,125,573
                                          ----------               ----------

OPERATING EXPENSES:
   Fuel                                       45,650                   47,030
   Purchased Power:
     Electricity Marketing and Trading       637,921                  799,639
     AEP Affiliates                           71,582                   72,272
   Other Operation                            54,158                   54,548
   Maintenance                                14,140                   18,780
   Depreciation and Amortization              32,736                   31,482
   Taxes Other Than Income Taxes              30,276                   30,687
   Income Taxes                               17,304                   23,020
                                          ----------               ----------
           TOTAL OPERATING EXPENSES          903,767                1,077,458
                                          ----------               ----------

OPERATING INCOME                              45,548                   48,115
NONOPERATING INCOME                          257,578                  252,846
NONOPERATING EXPENSES                        254,023                  247,690
NONOPERATING INCOME TAX EXPENSE (CREDIT)       1,452                   (2,133)
INTEREST CHARGES                              13,793                   17,733
                                          ----------               ----------
NET INCOME                                    33,858                   37,671
PREFERRED STOCK DIVIDEND REQUIREMENTS            181                      302
                                          ----------               ----------

EARNINGS APPLICABLE TO COMMON STOCK       $   33,677               $   37,369
                                          ==========               ==========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                           Three Months Ended March 31,
                                            2002                    2001
                                            ----                    ----
                                                (in thousands)
BALANCE AT BEGINNING OF PERIOD           $176,103                 $ 99,069

NET INCOME                                 33,858                   37,671

DEDUCTIONS:
  Cash Dividends Declared:
     Common Stock                          21,766                   20,738
     Cumulative Preferred Stock               175                      262
  Capital Stock Expense                       254                      254
                                         --------                 --------

BALANCE AT END OF PERIOD                 $187,766                 $115,486
                                         ========                 ========

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 BALANCE SHEETS
                                   (UNAUDITED)

                                            March 31, 2002          December 31, 2001
                                            --------------          -----------------
                                                           (in thousands)

<S>                                              <C>                        <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                    $1,575,390                 $1,574,506
   Transmission                                     402,391                    401,405
   Distribution                                   1,167,184                  1,159,105
   General                                          143,532                    146,732
   Construction Work in Progress                     85,048                     72,572
                                                 ----------                 ----------
       Total Electric Utility Plant               3,373,545                  3,354,320
   Accumulated Depreciation and Amortization      1,399,457                  1,377,032
                                                 ----------                 ----------
        NET ELECTRIC UTILITY PLANT                1,974,088                  1,977,288
                                                 ----------                 ----------

OTHER PROPERTY AND INVESTMENTS                       39,793                     40,369
                                                 ----------                 ----------

LONG-TERM ENERGY TRADING CONTRACTS                  339,985                    193,915
                                                 ----------                 ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                          6,497                     12,358
   Accounts Receivable:
      Customers                                      46,077                     41,770
      Affiliated Companies                           98,987                     63,470
      Miscellaneous                                  19,325                     16,968
      Allowance for Uncollectible Accounts             (719)                      (745)
   Fuel - at average cost                            21,127                     20,019
   Materials and Supplies - at average cost          34,240                     38,984
   Accrued Utility Revenues                          12,334                      7,087
   Energy Trading Contracts                         500,539                    347,198
   Prepayments                                       32,951                     28,733
                                                 ----------                 ----------
        TOTAL CURRENT ASSETS                        771,358                    575,842
                                                 ----------                 ----------

REGULATORY ASSETS                                   258,725                    262,267
                                                 ----------                 ----------

DEFERRED CHARGES                                     45,731                     56,187
                                                 ----------                 ----------

        TOTAL ASSETS                             $3,429,680                 $3,105,868
                                                 ==========                 ==========

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

                                                    March 31, 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                                          574,622                     574,369
   Retained Earnings                                        187,766                     176,103
                                                         ----------                  ----------
        Total Common Shareowner's Equity                    803,414                     791,498
   Cumulative Preferred Stock - Subject to
    Mandatory Redemption                                     10,000                      10,000
   Long-term Debt                                           571,441                     571,348
                                                         ----------                  ----------

           TOTAL CAPITALIZATION                           1,384,855                   1,372,846
                                                         ----------                  ----------

OTHER NONCURRENT LIABILITIES                                 34,687                      36,715
                                                         ----------                  ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                       220,500                     220,500
   Advances from Affiliates                                 210,490                     181,384
   Accounts Payable - General                                53,925                      62,393
   Accounts Payable - Affiliated Companies                   99,514                      83,697
   Taxes Accrued                                             96,417                     116,364
   Interest Accrued                                          14,514                      10,907
   Energy Trading Contracts                                 481,723                     334,958
   Other                                                     33,421                      34,600
                                                         ----------                  ----------

           TOTAL CURRENT LIABILITIES                      1,210,504                   1,044,803
                                                         ----------                  ----------

DEFERRED INCOME TAXES                                       444,447                     443,722
                                                         ----------                  ----------

DEFERRED INVESTMENT TAX CREDITS                              36,398                      37,176
                                                         ----------                  ----------

LONG-TERM ENERGY TRADING CONTRACTS                          301,879                     157,706
                                                         ----------                  ----------

DEFERRED CREDITS                                             16,910                      12,900
                                                         ----------                  ----------

CONTINGENCIES (Note 8)

           TOTAL CAPITALIZATION AND LIABILITIES          $3,429,680                  $3,105,868
                                                         ==========                  ==========

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

                                                            Three Months Ended March 31,
                                                                     (in thousands)
                                                              2002                  2001
                                                              ----                  ----
<S>                                                       <C>                     <C>
OPERATING ACTIVITIES:
   Net Income                                             $  33,858               $  37,671
   Adjustments for Noncash Items:
      Depreciation and Amortization                          32,786                  31,638
      Deferred Federal Income Taxes                            (313)                  6,957
      Deferred Investment Tax Credits                          (778)                   (836)
      Mark to Market of Energy Trading Contracts             (5,849)                (30,008)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                             (42,207)                (10,067)
      Fuel, Materials and Supplies                            3,636                  (4,345)
      Accrued Utility Revenues                               (5,247)                  9,638
      Accounts Payable                                        7,349                  17,605
      Taxes Accrued                                         (19,947)                (38,504)
      Interest Accrued                                        3,607                  11,122
      Other Assets                                              992                  12,798
      Other Liabilities                                       3,505                  (6,442)
                                                          ---------                --------
           Net Cash Flows From Operating Activities          11,392                  37,227
                                                          ---------                --------

INVESTING ACTIVITIES:
      Construction Expenditures                             (24,807)                (33,007)
      Proceeds from Sale of Property                            389                    -
                                                          ---------                --------
           Net Cash Flows Used For Investing Activities     (24,418)                (33,007)
                                                          ---------                --------

FINANCING ACTIVITIES:
      Change in Money Pool                                   29,106                  13,477
      Dividends Paid on Common Stock                        (21,766)                (20,738)
      Dividends Paid on Cumulative Preferred Stock             (175)                   (262)
                                                          ---------                --------
           Net Cash Flows Used For Financing Activities       7,165                  (7,523)
                                                          ---------                --------

Net Increase (Decrease) in Cash and Cash Equivalents         (5,861)                 (3,303)
Cash and Cash Equivalents at Beginning of Period             12,358                  11,600
                                                          ---------                --------
Cash and Cash Equivalents at End of Period                $   6,497                $  8,297
                                                          =========                ========
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized  amounts was $9,725,000 and $6,127,000
and  for  income  taxes  was  $11,198,000  and  $17,485,000  in 2002  and  2001,
respectively. Noncash acquisitions under capital leases were $84,000 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

                    FIRST QUARTER 2002 vs. FIRST QUARTER 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
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.
<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 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  $21 million or 66% due primarily to a reduction
in generation as a result of a refueling outage at one unit of I&M's Cook Plant,
maintenance outages at Rockport Plant and lower margins on electricity sales.
<PAGE>
        Operating  revenues decreased 20% 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:
                                    Increase (Decrease)
                                          (in millions)         %

         Electricity Marketing                $(225.6)        (20)
          and Trading*
         Energy Delivery*                        (3.4)         (4)
         Sales to AEP Affiliates                (23.8)        (33)
                                              -------
              Total                           $(252.8)        (20)
                                              =======

         *Reflects  the  allocation  of certain  transmission  and  distribution
         revenues included in bundled retail rates to energy delivery.

        The decrease in electricity  marketing and trading revenues was due to a
decline in wholesale  prices  reflecting soft demand caused by the slow economic
recovery and mild winter weather. 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 and both units of Rockport  Plant
were  scheduled  for  planned  boiler  maintenance.  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 19% in 2002.  The changes in the components
of operating expenses were:
                                            Increase (Decrease)
                                            -------------------
                                            (in millions)              %
                                            -------------              -

         Fuel                                         $  (9.8)          (15)
         Electricity Marketing and Trading
          Purchases                                    (216.2)          (24)
         Purchases from AEP Affiliates                  (10.0)          (16)
         Other Operation                                 14.4            15
         Maintenance                                      2.9            10
         Depreciation and Amortization                    1.1             3
         Taxes Other Than Income Taxes                     -             -
         Income Taxes                                   (12.8)          (68)
                                                      -------
              Total                                   $(230.4)          (19)
                                                      =======

        Fuel  expense  decreased  primarily  due to the  decline  in  generation
reflecting the plant outages, mild winter weather and a slow economic recovery.
        The decrease in  electricity  marketing and trading  purchases  resulted
mainly from the decrease in energy prices.
        Purchases from AEP affiliates declined due to the Rockport Plant outages
as I&M is required to purchase  AEGCo's  Rockport Plant  generation  under their
unit power agreement.
    Other operation expense increased due to higher costs resulting from the
generating plants outages, property insurance and employee benefit costs.
<PAGE>
        The increase in maintenance expense is primarily due to costs related to
the outages.
        Income tax expense  attributable to operations  decreased  significantly
due primarily to a decline in pre-tax operating income.
        The decrease in nonoperating income and nonoperating  expenses is 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.
        Interest  charges  decreased  due to a decline in  short-term  rates and
lower outstanding borrowings.
<PAGE>
                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                           Three Months Ended March 31,
                                             2002                  2001
                                             ----                  ----
                                             (in thousands)
OPERATING REVENUES:
   Electricity Marketing and Trading    $  917,013            $1,142,617
   Energy Delivery                          74,537                77,937
   Sales to AEP Affiliates                  47,209                70,984
                                        ----------            ----------

           TOTAL OPERATING REVENUES      1,038,759             1,291,538
                                        ----------            ----------

OPERATING EXPENSES:
   Fuel                                     54,156                63,973
   Purchased Power:
      Electricity Marketing and Trading    691,806               908,039
      AEP Affiliates                        53,507                63,548
   Other Operation                         111,766                97,363
   Maintenance                              31,043                28,175
   Depreciation and Amortization            41,866                40,723
   Taxes Other Than Income Taxes            18,241                18,238
   Income Taxes                              6,011                18,781
                                        ----------            ----------

           TOTAL OPERATING EXPENSES      1,008,396             1,238,840
                                        ----------            ----------

OPERATING INCOME                            30,363                52,698

NONOPERATING INCOME                        295,185               302,274

NONOPERATING EXPENSES                      291,491               295,714

NONOPERATING INCOME TAX EXPENSE (CREDIT)      (425)                2,115

INTEREST CHARGES                            23,424                24,780
                                        ----------            ----------

NET INCOME                                  11,058                32,363

PREFERRED STOCK DIVIDEND REQUIREMENTS        1,155                 1,155
                                        ----------            ----------

EARNINGS APPLICABLE TO COMMON STOCK     $    9,903            $   31,208
                                        ==========            ==========

                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                         Three Months Ended March 31,
                                          2002                  2001
                                          ----                  ----
                                            (in thousands)
NET INCOME                              $11,058               $32,363

OTHER COMPREHENSIVE INCOME (LOSS)
    Cash Flow Interest Rate Hedge         1,259                (1,919)
                                        -------               -------

COMPREHENSIVE INCOME                    $12,317               $30,444
                                        =======               =======

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

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

<PAGE>

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

                                      Three Months Ended March 31,
                                     2002                    2001
                                     ----                    ----
                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD     $74,605                  $ 3,443

NET INCOME                          11,058                   32,363

DEDUCTIONS:
 Cash Dividends Declared -
    Cumulative Preferred Stock       1,122                    1,122
  Capital Stock Expense                 33                       33
                                   -------                  -------

BALANCE AT END OF PERIOD           $84,508                  $34,651
                                   =======                  =======

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

                                               March 31, 2002           December 31, 2001
                                               --------------           -----------------
                                                             (in thousands)
<S>                                                 <C>                        <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                       $2,759,924                 $2,758,160
   Transmission                                        957,905                    957,336
   Distribution                                        899,146                    900,921
   General (including nuclear fuel)                    220,140                    233,005
   Construction Work in Progress                        91,819                     74,299
                                                    ----------                 ----------
        Total Electric Utility Plant                 4,928,934                  4,923,721
   Accumulated Depreciation and Amortization         2,469,854                  2,436,972
                                                    ----------                 ----------
             NET ELECTRIC UTILITY PLANT              2,459,080                  2,486,749
                                                    ----------                 ----------

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
  DISPOSAL TRUST FUNDS                                 844,616                    834,109
                                                    ----------                 ----------

LONG-TERM ENERGY TRADING CONTRACTS                     385,768                    215,544
                                                    ----------                 ----------

OTHER PROPERTY AND INVESTMENTS                         124,762                    127,977
                                                    ----------                 ----------

CURRENT ASSETS:
   Cash and Cash Equivalents                            10,849                     16,804
   Advances to Affiliates                               37,422                     46,309
   Accounts Receivable:
      Customers                                         66,101                     60,864
      Affiliated Companies                              71,244                     31,908
      Miscellaneous                                     39,204                     25,398
      Allowance for Uncollectible Accounts                (804)                      (741)
   Fuel - at average cost                               28,264                     28,989
   Materials and Supplies - at average cost             86,643                     91,440
   Energy Trading Contracts                            579,967                    399,195
   Accrued Utility Revenues                              5,405                      2,072
   Prepayments                                           9,838                      6,497
                                                    ----------                 ----------
          TOTAL CURRENT ASSETS                         934,133                    708,735
                                                    ----------                 ----------

REGULATORY ASSETS                                      414,045                    408,927
                                                    ----------                 ----------

DEFERRED CHARGES                                        40,943                     34,967
                                                    ----------                 ----------

          TOTAL ASSETS                              $5,203,347                 $4,817,008
                                                    ==========                 ==========

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

                                                    March 31, 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                                         733,249                     733,216
   Accumulated Other Comprehensive Income (Loss)            (2,576)                     (3,835)
   Retained Earnings                                        84,508                      74,605
                                                        ----------                  ----------
        Total Common Shareowner's Equity                   871,765                     860,570
   Cumulative Preferred Stock:
      Not Subject to Mandatory Redemption                    8,736                       8,736
      Subject to Mandatory Redemption                       64,945                      64,945
   Long-term Debt                                        1,313,389                   1,312,082
                                                        ----------                  ----------

           TOTAL CAPITALIZATION                          2,258,835                   2,246,333
                                                        ----------                  ----------

OTHER NONCURRENT LIABILITIES:
   Nuclear Decommissioning                                 605,988                     600,244
   Other                                                    86,872                      87,025
                                                        ----------                  ----------

           TOTAL OTHER NONCURRENT LIABILITIES              692,860                     687,269
                                                        ----------                  ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                      340,000                     340,000
   Accounts Payable:
      General                                               77,745                      90,817
      Affiliated Companies                                  46,249                      43,956
   Taxes Accrued                                            91,152                      69,761
   Interest Accrued                                         28,265                      20,691
   Obligations Under Capital Leases                          9,483                      10,840
   Energy Trading Contracts                                554,916                     383,714
   Other                                                    88,790                      72,435
                                                        ----------                  ----------

           TOTAL CURRENT LIABILITIES                     1,236,600                   1,032,214
                                                        ----------                  ----------

DEFERRED INCOME TAXES                                      389,177                     400,531
                                                        ----------                  ----------

DEFERRED INVESTMENT TAX CREDITS                            103,604                     105,449
                                                        ----------                  ----------

DEFERRED GAIN ON SALE AND LEASEBACK -
 ROCKPORT PLANT UNIT 2                                      76,665                      77,592
                                                        ----------                  ----------

LONG-TERM ENERGY TRADING CONTRACTS                         347,151                     175,581
                                                        ----------                  ----------

DEFERRED CREDITS                                            98,455                      92,039
                                                        ----------                  ----------

CONTINGENCIES (Note 8)

                TOTAL CAPITALIZATION AND LIABILITIES    $5,203,347                  $4,817,008
                                                        ==========                  ==========

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

                                                             Three Months Ended March 31,
                                                                2002                  2001
                                                                ----                  ----
                                                                     (in thousands)
<S>                                                       <C>                      <C>
OPERATING ACTIVITIES:
   Net Income                                             $  11,058                $  32,363
   Adjustments for Noncash Items:
      Depreciation and Amortization                          42,184                   41,589
      Amortization (Deferral) of Incremental
      Nuclear Refueling Outage Expenses (net)               (24,130)                     316
      Unrecovered Fuel and Purchased Power Costs              9,375                    9,375
      Amortization of Nuclear Outage Costs                   10,000                   10,000
      Deferred Federal Income Taxes                          (7,132)                  (2,462)
      Deferred Investment Tax Credits                        (1,845)                  (1,868)
      Mark-to-Market of Energy Trading Contracts             (3,708)                 (17,447)
      Deferred Property Taxes                                (8,409)                  (9,731)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                             (58,316)                  43,803
      Fuel, Materials and Supplies                            5,522                   (6,098)
      Accrued Utility Revenues                               (3,333)                    -
      Accounts Payable                                      (10,779)                 (21,638)
      Taxes Accrued                                          21,391                   28,166
      Rent Accrued - Rockport Plant Unit 2                   18,464                   18,464
   Change in Other Assets                                     8,328                     (735)
   Change in Other Liabilities                                4,008                  (17,909)
                                                          ---------                ---------
           Net Cash Flows From Operating Activities          12,678                  106,188
                                                          ---------                ---------

INVESTING ACTIVITIES:
      Construction Expenditures                             (26,398)                 (18,241)
      Buyout of Nuclear Fuel Leases                            -                     (92,616)
                                                          ---------                ---------
           Net Cash Flows Used For Investing Activities     (26,398)                (110,857)
                                                          ---------                ---------

FINANCING ACTIVITIES:
      Change in Advances from Affiliates (net)                8,887                    4,878
      Dividends Paid on Cumulative Preferred Stock           (1,122)                  (1,122)
                                                          ---------                ---------
           Net Cash Flows From Financing Activities           7,765                    3,756
                                                          ---------                ---------

Net Decrease in Cash and Cash Equivalents                    (5,955)                    (913)
Cash and Cash Equivalents at Beginning of Period             16,804                   14,835
                                                          ---------                ---------
Cash and Cash Equivalents at End of Period                $  10,849                $  13,922
                                                          =========                =========
</TABLE>
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $15,090,000 and
$21,610,000 and for income taxes was $(470,000) and $7,471,000 in 2002 and 2001,
respectively. Noncash acquisitions under capital leases were $991,000 in 2001.

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

                    FIRST QUARTER 2002 vs. FIRST QUARTER 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
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.
<PAGE>
           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  "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
        Decreases  in revenues  were offset by sharper  decreases  in  operating
expenses which resulted in an increase in net income of $3 million or 45%.
        The following analyzes the changes in operating revenues:
                                  Increase (Decrease)
                                        (in millions)           %

         Electricity Marketing
          And Trading*                         $(103)         (25)
         Energy Delivery*                         (1)          (3)
         Sales to AEP Affiliates                  (4)         (38)
                                               -----
              Total                            $(108)         (23)
                                               =====

         *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 and mild winter  weather.  In the first  quarter of 2002 the AEP
Power  Pool  grew its  electric  trading  business  resulting  in a  significant
increase  in the  number of forward  electricity  contracts  entered  into AEP's
traditional  marketing area (up to two  transmission  systems from AEP's service
territory).  This growth in volume was offset by reduced  demand  which  lowered
selling prices and margins.  Depressed  prices were  experienced in both trading
and wholesale  sales,  resulting in an overall  decrease in revenues due to mild
weather and a slow recovery from the economic recession. Retail activity for the
period was comparable to that of the same period last year.
<PAGE>
        Changes in the components of operating expenses were:

                                        Increase (Decrease)
                                       -------------------
                                              (in millions)            %
                                             -------------             -

         Fuel                                        $   4            21
         Electricity Marketing and
           Trading Purchases                          (106)          (30)
         Purchases from AEP Affiliates                  (7)          (19)
         Other Operation                                (2)          (15)
         Maintenance                                    (1)          (16)
                                                     -----
              Total                                  $(112)          (25)
                                                     =====

        Fuel expense  increased due to  difficulties  experienced  by one of the
Company's main coal  suppliers  forcing KPCo to go to the open market to address
shortfalls  in supply at higher  prices in the coal spot market.  Management  is
exploring opportunities for alternative suppliers and contracted rates.
        Purchased power expense  decreases were primarily  attributable to lower
prices resulting from mild winter weather and declining demand for electricity.
        Other operation expense decreased due to a decrease in trading incentive
cost accruals.
        Maintenance  expense decreased as a result of adjustments to labor force
and contractor support, the latter being converted to an "as needed" versus full
time basis.
        The decrease in  nonoperating  income and expenses was due to a decrease
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 and mild weather.
 <PAGE>
                             KENTUCKY POWER COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                          Three Months Ended March 31,
                                           2002                   2001
                                           ----                   ----
                                                       (in thousands)
OPERATING REVENUES:
   Electric Marketing and Trading       $310,157                $413,133
   Energy Delivery                        35,129                  36,327
   Sales to AEP Affiliates                 6,022                   9,697
                                        --------                --------

           TOTAL OPERATING REVENUES      351,308                 459,157
                                        --------                --------

OPERATING EXPENSES:
   Fuel                                   21,767                  17,956
   Purchased Power
      Electricity Marketing and Trading  252,005                 358,230
      AEP Affiliates                      28,941                  35,635
   Other Operation                        12,469                  14,728
   Maintenance                             4,549                   5,429
   Depreciation and Amortization           8,257                   8,027
   Taxes Other Than Income Taxes           2,135                   2,049
   Income Taxes                            5,701                   5,834
                                        --------                --------

           TOTAL OPERATING EXPENSES      335,824                 447,888
                                        --------                --------

OPERATING INCOME                          15,484                  11,269

NONOPERATING INCOME                      101,984                 113,516

NONOPERATING EXPENSES                    100,912                 111,273

NONOPERATING INCOME TAX CREDIT               190                     567

INTEREST CHARGES                           6,500                   7,004
                                        --------                --------

           NET INCOME                   $ 10,246                $  7,075
                                        ========                ========

                       STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                                  Three Months Ended March 31,
                                                 2002                     2001
                                                 ----                     ----
                                                       (in thousands)
NET INCOME                                     $10,246                 $ 7,075

STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge                      516                  (1,354)
                                               -------                 -------

COMPREHENSIVE INCOME                           $10,762                 $ 5,721
                                               =======                 =======

The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
                             KENTUCKY POWER COMPANY
                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                        Three Months Ended March 31,
                                        2002                     2001
                                        ----                     ----
                                               (in thousands)

BALANCE AT BEGINNING OF PERIOD       $48,833                   $57,513

NET INCOME                            10,246                     7,075

CASH DIVIDENDS DECLARED:
     Common Stock                      7,044                     7,561
                                     -------                   -------

BALANCE AT END OF PERIOD             $52,035                   $57,027
                                     =======                   =======

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


                                                  March 31, 2002          December 31, 2001
                                                  --------------          -----------------
                                                                 (in thousands)
<S>                                                    <C>                        <C>
ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                          $  271,096                 $  271,070
   Transmission                                           371,924                    374,116
   Distribution                                           401,798                    402,537
   General                                                 64,815                     65,059
   Construction Work in Progress                           31,852                     15,633
                                                           ------                 ----------
        Total Electric Utility Plant                    1,141,485                  1,128,415
   Accumulated Depreciation and Amortization              389,694                    384,104
                                                          -------                    -------
          NET ELECTRIC UTILITY PLANT                      751,791                    744,311
                                                          -------                    -------

OTHER PROPERTY AND INVESTMENTS                              6,472                      6,492
                                                            -----                      -----

LONG-TERM ENERGY TRADING CONTRACTS                        134,272                     77,972
                                                          -------                     ------

CURRENT ASSETS:
   Cash and Cash Equivalents                                  417                      1,947
   Accounts Receivable:
      Customers                                            20,762                     20,036
      Affiliated Companies                                 29,249                     16,012
      Miscellaneous                                         3,937                      3,333
      Allowance for Uncollectible Accounts                   (233)                      (264)
   Fuel - at average cost                                  14,026                     12,060
   Materials and Supplies - at average cost                15,559                     15,766
   Accrued Utility Revenues                                 8,316                      5,395
   Energy Trading Contracts                               198,129                    139,605
   Prepayments                                                383                      1,314
                                                              ---                      -----
          TOTAL CURRENT ASSETS                            290,545                    215,204
                                                          -------                    -------

REGULATORY ASSETS                                          98,822                     97,692
                                                           ------                     ------

DEFERRED CHARGES                                           10,334                     11,572
                                                           ------                     ------

          TOTAL ASSETS                                 $1,292,236                 $1,153,243
                                                       ==========                 ==========

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


                                                       March 31, 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)               (1,387)            (1,903)
   Retained Earnings                                           52,035             48,833
                                                               ------             ------
        Total Common Shareowner's Equity                      259,848            256,130
   Long-term Debt                                             236,646            251,093
                                                              -------            -------

           TOTAL CAPITALIZATION                               496,494            507,223
                                                              -------            -------

OTHER NONCURRENT LIABILITIES                                   11,670             11,929
                                                               ------             ------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                         109,500             95,000
   Advances from Affiliates                                    76,794             66,200
   Accounts Payable:
      General                                                  20,428             24,050
      Affiliated Companies                                     31,797             22,557
   Customer Deposits                                            6,260              4,461
   Taxes Accrued                                               12,015             10,305
   Interest Accrued                                             5,363              5,269
   Energy Trading Contracts                                   199,434            144,364
   Other                                                       11,784             12,296
                                                               ------             ------

           TOTAL CURRENT LIABILITIES                          473,375            384,502
                                                              -------            -------

DEFERRED INCOME TAXES                                         168,086            168,304
                                                              -------            -------

DEFERRED INVESTMENT TAX CREDITS                                10,110             10,405
                                                               ------             ------

LONG-TERM ENERGY TRADING CONTRACTS                            119,222             63,412
                                                              -------             ------

DEFERRED CREDITS                                               13,279              7,468
                                                               ------              -----

CONTINGENCIES (Note 8)

           TOTAL CAPITALIZATION AND LIABILITIES            $1,292,236         $1,153,243
                                                           ==========         ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                             KENTUCKY POWER COMPANY
                            STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                       Three Months Ended March 31,
                                                                          2002                2001
                                                                          ----                ----
                                                                              (in thousands)
<S>                                                                    <C>                   <C>
OPERATING ACTIVITIES:
   Net Income                                                          $ 10,246              $7,075
   Adjustments for Noncash Items:
      Depreciation and Amortization                                       8,257               8,029
      Deferred Federal Income Taxes                                        (556)              4,194
      Deferred Investment Tax Credits                                      (295)               (297)
      Deferred Fuel Costs (net)                                           1,542              (1,271)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                         (14,598)             10,227
      Fuel, Materials and Supplies                                       (1,759)               (350)
      Accrued Utility Revenues                                           (2,921)              3,243
      Accounts Payable                                                    5,618               3,177
      Taxes Accrued                                                       1,710              (3,691)
      Mark to Market Energy Contracts                                    (1,858)             (5,976)
   Change in Other Assets                                                 4,997             (10,086)
   Change in Other Liabilities                                              435               5,871
                                                                            ---               -----
           Net Cash Flows From Operating Activities                      10,818              20,145
                                                                         ------              ------

INVESTING ACTIVITIES:
      Construction Expenditures                                         (15,898)             (5,746)
      Proceeds from Sales of Property                                      -                    216
                                                                           ----                 ---
           Net Cash Flow Used for Investing Activities                  (15,898)             (5,530)
                                                                        -------              ------

FINANCING ACTIVITIES:
      Change in Advances from Affiliates (net)                           10,594              (8,033)
      Dividends Paid                                                     (7,044)             (7,561)
                                                                         ------              ------
           Net Cash Flows From (Used For) Financing Activities            3,550             (15,594)
                                                                          -----             -------

Net Decrease in Cash and Cash Equivalents                                (1,530)               (979)
Cash and Cash Equivalents at Beginning of Period                          1,947               2,270
                                                                          -----               -----
Cash and Cash Equivalents at End of Period                                $ 417              $1,291
                                                                          =====              ======
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized  amounts was $6,328,000 and $4,529,000
and  for  income  taxes  was   $3,053,000  and  $4,354,000  in  2002  and  2001,
respectively.  Noncash  acquisitions  under  capital  leases  were  $22,000  and
$661,000 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

                    FIRST QUARTER 2002 vs. FIRST QUARTER 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.

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.
<PAGE>
           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.
        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.
<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 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  $10.7  million or 20%.  While  revenues  declined
$316.1 million,  operating  expenses declined even more resulting in an increase
in net  income.  Margins  increased  in 2002 for  electricity  sales  to  retail
customers,  reflecting the spread between capped or frozen retail rates and weak
wholesale energy prices and cost of fuel. Weak wholesale prices,  that benefited
our retail sales,  resulted in lower margins  reducing  earnings from  wholesale
energy marketing and trading.
<PAGE>
        The following analyzes the changes in operating revenues:
                                   Increase (Decrease)
                                         (in millions)        %

         Electricity Marketing              $(294.6)        (21)
          and Trading*
         Energy Delivery*                       9.9           8
         Sales to AEP Affiliates              (31.4)        (22)
                                              -----
              Total                         $(316.1)        (19)
                                            =======

         *Reflects  the  allocation  of certain  transmission  and  distribution
         revenues included in bundled retail rates to energy delivery.

        The  decline  in  revenues  is  mainly  due to a  decrease  in  electric
marketing and trading revenues.  The decrease was driven largely by a decline in
demand  due to mild  winter  weather  and the slow  recovery  from the  economic
recession. Heating degree days were down 12% and electricity sales to industrial
customers  decreased  2%.  Revenues from sales to AEP  affiliates  declined as a
result of the effects of the mild weather and the economy.
        Operating expenses declined 20% in 2002.  The changes in the components
of operating expenses were:
                                                 Increase (Decrease)
                                                 -------------------
                                                 (in millions)             %
                                                 -------------             -

         Fuel                                             $ (58.2)          (29)
         Electricity Marketing and
           Trading Purchases                               (282.1)          (24)
         Purchases from AEP Affiliates                       (2.4)          (14)
         Other Operation                                      2.1             2
         Maintenance                                         (6.4)          (18)
         Depreciation and Amortization                        2.6             4
         Taxes Other Than Income Taxes                        5.6            14
         Income Taxes                                         3.8            12
                                                              ---
              Total                                       $(335.0)          (20)
                                                          =======

        The decrease in fuel expense was primarily  attributable  to a reduction
in power  generation and lower fuel costs  reflecting  lower market prices.  Net
generation  decreased by 8% due to the reduced demand for electricity.  The cost
of  purchased  power for  resale  was also lower due to the  reduced  demand,  a
continuation  of the market  conditions  that developed in the fourth quarter of
2001.
        Maintenance  expense declined due primarily due to a reduction in boiler
plant overhauls.
        Taxes other than income taxes increased due to changes in taxes assessed
on  utilities  under the Ohio  Restructuring  Law.  The law  imposed a new state
excise tax in 2002  replacing  the state gross  receipts  tax and provided for a
reduction in taxable rates on generation property.
        The  increase  in income  taxes is  predominately  due to a increase  in
pre-tax operating income.
<PAGE>
                       OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                              Three Months Ended March 31,
                                                  2002             2001
                                                  ----             ----
                                                     (in thousands)
OPERATING REVENUES:
   Electricity Marketing and Trading        $1,132,192        $1,426,817
   Energy Delivery                             141,760           131,849
   Sales to AEP Affiliates                     109,634           140,999
                                               -------           -------

           TOTAL OPERATING REVENUES          1,383,586         1,699,665
                                             ---------         ---------

OPERATING EXPENSES:
   Fuel                                        142,336           200,561
   Purchased Power:
      Electricity Marketing and Trading        880,157         1,162,284
      AEP Affiliates                            14,227            16,622
   Other Operation                              90,520            88,406
   Maintenance                                  28,988            35,400
   Depreciation and Amortization                62,621            60,059
   Taxes Other Than Income Taxes                45,839            40,236
   Income Taxes                                 35,182            31,341
                                                ------            ------

           TOTAL OPERATING EXPENSES          1,299,870         1,634,909
                                             ---------         ---------

OPERATING INCOME                                83,716            64,756

NONOPERATING INCOME                            356,341           370,474

NONOPERATING EXPENSES                          350,823           356,858

NONOPERATING INCOME TAX EXPENSE (CREDIT)         3,722             2,508

INTEREST CHARGES                                21,461            22,467
                                                ------            ------

NET INCOME                                      64,051            53,397

PREFERRED STOCK DIVIDEND REQUIREMENTS              314               314
                                                   ---               ---

EARNINGS APPLICABLE TO COMMON STOCK           $ 63,737          $ 53,083
                                              ========          ========

                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                               Three Months Ended March 31,
                                                2002                  2001
                                                ----                  ----
                                                     (in thousands)
NET INCOME                                    $64,051               $53,397

OTHER COMPREHENSIVE LOSS
    Foreign Currency Exchange Rate Hedge         (201)                 (220)
                                                 ----                  ----

COMPREHENSIVE INCOME                          $63,850               $53,177
                                              =======               =======

The common stock of the Company is wholly owned by AEP.

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

                                     Three Months Ended March 31,
                                      2002                  2001
                                      ----                  ----
                                           (in thousands)
BALANCE AT BEGINNING OF PERIOD     $401,297              $398,086

NET INCOME                           64,051                53,397

CASH DIVIDENDS DECLARED:
     Common Stock                    32,582                35,744
     Cumulative Preferred Stock         314                   314
                                        ---                   ---

BALANCE AT END OF PERIOD           $432,452              $415,425
                                   ========              ========

The common stock of the Company is wholly owned by AEP.

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

                                             March 31, 2002    December 31, 2001
                                             --------------    -----------------
                                                       (in thousands)

ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                    $3,018,212           $3,007,866
   Transmission                                     894,334              891,283
   Distribution                                   1,084,329            1,081,122
   General                                          242,446              245,232
   Construction Work in Progress                    201,524              165,073
                                                    -------              -------
        Total Electric Utility Plant              5,440,845            5,390,576
   Accumulated Depreciation and Amortization      2,483,039            2,452,571
                                                  ---------            ---------
          NET ELECTRIC UTILITY PLANT              2,957,806            2,938,005
                                                  ---------            ---------

OTHER PROPERTY AND INVESTMENTS                       61,459               62,303
                                                     ------               ------

LONG-TERM ENERGY TRADING CONTRACTS                  466,283              263,734
                                                    -------              -------

CURRENT ASSETS:
   Cash and Cash Equivalents                         39,351                8,848
   Accounts Receivable:
      Customers                                      93,816               84,694
      Affiliated Companies                          125,302              148,563
      Miscellaneous                                  36,835               20,409
      Allowance for Uncollectible Accounts           (1,048)              (1,379
   Fuel - at average cost                            98,417               84,724
   Materials and Supplies - at average cost          81,491               88,768
   Accrued Utility Revenues                           5,368                 -
   Energy Trading Contracts                         685,740              472,246
   Prepayments and Other                             32,787               20,865
                                                     ------               ------
          TOTAL CURRENT ASSETS                    1,198,059              927,738
                                                  ---------              -------

REGULATORY ASSETS                                   628,491              644,625
                                                    -------              -------

DEFERRED CHARGES                                     64,629               79,662
                                                     ------               ------

          TOTAL ASSETS                           $5,376,727           $4,916,067
                                                 ==========           ==========
See Notes to Financial Statements beginning on page L-1.
<PAGE>
                       OHIO POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                              March 31, 2002   December 31, 2001
                                              --------------   -----------------
                                                          (in thousands)

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)        (397)              (196)
   Retained Earnings                                 432,452            401,297
                                                     -------            -------
        Total Common Shareholder's Equity          1,215,739          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                                  1,199,009          1,203,841
                                                   ---------          ---------

           TOTAL CAPITALIZATION                    2,440,246          2,414,124
                                                   ---------          ---------

OTHER NONCURRENT LIABILITIES                         126,924            130,386
                                                     -------            -------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                  5,000               -
   Advances from Affiliates                          389,386            300,213
   Accounts Payable - General                        124,685            134,418
   Accounts Payable - Affiliated Companies           110,429            176,520
   Customer Deposits                                   5,961              5,452
   Taxes Accrued                                     148,268            126,770
   Interest Accrued                                   24,850             17,679
   Obligations Under Capital Leases                   14,219             16,405
   Energy Trading Contracts                          656,059            456,047
   Other                                              77,898             87,070
                                                      ------             ------

           TOTAL CURRENT LIABILITIES               1,556,755          1,320,574
                                                   ---------          ---------

DEFERRED INCOME TAXES                                796,885            797,889
                                                     -------            -------

DEFERRED INVESTMENT TAX CREDITS                       21,160             21,925
                                                      ------             ------

LONG-TERM ENERGY TRADING CONTRACTS                   410,895            214,487
                                                     -------            -------

DEFERRED CREDITS                                      23,862             16,682
                                                      ------             ------

CONTINGENCIES (Note 8)

       TOTAL CAPITALIZATION AND LIABILITIES       $5,376,727         $4,916,067
                                                  ==========         ==========

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

                                                            Three Months Ended March 31,
                                                              2002                  2001
                                                              ----                  ----
                                                                   (in thousands)
<S>                                                              <C>             <C>
OPERATING ACTIVITIES:
   Net Income                                                    $64,051         $53,397
   Adjustments for Noncash Items:
      Depreciation                                                43,196          52,853
      Amortization of Transition Assets                           19,425          19,256
      Deferred Federal Income Taxes                               (4,649)         (1,068)
      Amortization of Deferred Property Taxes                     14,717          19,992
      Mark to Market of Energy Trading Contracts                 (16,055)        (45,268)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                   (2,618)          1,274
      Fuel, Materials and Supplies                                (6,416)        (17,131)
      Accrued Utility Revenues                                    (5,368)            264
      Prepayments                                                (11,822)        (22,537)
      Accounts Payable                                           (75,824)        (34,942)
      Customer Deposits                                              509          89,622
      Taxes Accrued                                               21,498         (51,420)
      Interest Accrued                                             7,171          11,106
   Other Operating Assets                                          1,388           1,267
   Other Operating Liabilities                                    (8,819)        (24,848)
                                                                  ------         -------
           Net Cash Flows From Operating Activities               40,384          51,817
                                                                  ------          ------

INVESTING ACTIVITIES:
      Construction Expenditures                                  (66,312)        (65,103)
      Proceeds from Sale of Property and Other                       154           5,885
                                                                     ---           -----
           Net Cash Flows Used For Investing Activities          (66,158)        (59,218)
                                                                 -------         -------

FINANCING ACTIVITIES:
      Change in Advances to Affiliates (net)                      89,173          75,950
      Retirement of Long-term Debt                                  -            (42,506)
      Dividends Paid on Common Stock                             (32,582)        (35,744)
      Dividends Paid on Cumulative Preferred Stock                  (314)           (314)
                                                                    ----            ----
           Net Cash Flows From (Used For) Financing Activities    56,277          (2,614)
                                                                  ------          ------

Net Increase (Decrease) in Cash and Cash Equivalents              30,503         (10,015)
Cash and Cash Equivalents at Beginning of Period                   8,848          31,393
                                                                   -----          ------
Cash and Cash Equivalents at End of Period                       $39,351         $21,378
                                                                 =======         =======
</TABLE>
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $13,900,000 and
$10,887,000  and for income taxes was  $(5,574,000)  and $50,242,000 in 2002 and
2001,  respectively.  Noncash acquisitions under capital leases were $98,000 and
$319,000 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

                    FIRST QUARTER 2002 vs. FIRST QUARTER 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 the 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
         The net loss  incurred by PSO  increased  $0.1  million or 5.6% in 2002
primarily  as a result of increased  maintenance  expense due to storm damage in
2002.
<PAGE>
The following analyzes the changes in operating revenues:
                                 Increase (Decrease)
                                 -------------------
                                       (in millions)          %
                                       -------------          -

Electricity Marketing
 and Trading*                             $(102.6)          (35)
Energy Delivery*                              3.3             7
Sales to AEP Affiliates                      (9.0)          (81)
                                             ----
    Total Revenues                        $(108.3)          (30)
                                          =======

*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 our share of AEP's  marketing  and trading  operations.
The decrease in electric  marketing and trading  revenue was driven largely by a
decline in demand due to mild  winter  weather  and the slow  recovery  from the
economic  recession.   Lower  energy  demand  depressed  margins  from  electric
marketing and trading.
         Operating expenses are as follows:
                                Increase (Decrease)
                                -------------------
                                      (in millions)            %
                                     -------------             -

Fuel                                       $ (53.7)          (48)
Electricity Marketing
 and Trading Purchases                       (32.7)          (25)
Purchases from AEP Affiliates                (20.5)          (55)
Other Operation                               (7.9)          (23)
Maintenance                                    4.3            44
Depreciation and Amortization                  1.4             7
Taxes Other Than Income Taxes                  0.1           N.M.
Income Taxes                                   0.6            28
                                               ---
    Total                                  $(108.4)          (31)
                                           =======

N.M. = Not Meaningful

         The  decrease  in fuel  expense was  primarily  due to lower fuel costs
reflecting lower market prices for natural gas and fuel oil.
         The cost per megawatt hour of purchased  power was lower due to reduced
demand,  a continuation  of the market  conditions  that developed in the fourth
quarter of 2001.
         Other operation  expense  decreased due mainly to reduced power trading
incentive  accruals,  lower transmission  wheeling charges and reduced factoring
and collections expenses.
         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 due to the cost of repowering Northeast
Station Units 1 & 2.
         The  increase in income  taxes is  predominately  due to an increase in
pre-tax income, and changes in certain book/tax timing differences accounted for
on a flow through basis.
         Lower interest rates and a reduction in outstanding  borrowings  caused
the reduction in interest charges.
<PAGE>
               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                                   (UNAUDITED)

                                           Three Months Ended March 31,
                                              2002                2001
                                              ----                ----
                                                    (in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading          $194,024            $296,599
Energy Delivery                              51,732              48,417
Sales to AEP Affiliates                       2,094              11,123
                                              -----              ------
           TOTAL OPERATING REVENUES         247,850             356,139
                                            -------             -------

OPERATING EXPENSES:
   Fuel                                      58,097             111,801
   Purchased Power:
      Electricity Marketing and Trading      96,520             129,179
      AEP Affiliates                         16,845              37,367
   Other Operation                           26,639              34,557
   Maintenance                               14,169               9,830
   Depreciation and Amortization             20,916              19,471
   Taxes Other Than Income Taxes              7,848               7,793
   Income Taxes                              (1,594)             (2,199)
                                             ------              ------
           TOTAL OPERATING EXPENSES         239,440             347,799
                                            -------             -------

OPERATING INCOME                              8,410               8,340

NONOPERATING INCOME                             106                 824

NONOPERATING EXPENSES                           595                 336

NONOPERATING INCOME TAX CREDIT                 (141)               (115)

INTEREST CHARGES                              9,710              10,503
                                              -----              ------

NET LOSS                                     (1,648)             (1,560)

PREFERRED STOCK DIVIDEND REQUIREMENTS            53                  53
                                                 --                  --

EARNINGS LOSS APPLICABLE TO COMMON STOCK   $ (1,701)           $ (1,613)
                                           ========            ========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                     Three Months Ended March 31,
                                  2002                       2001
                                  ----                       ----
                                            (in thousands)
BALANCE AT BEGINNING OF PERIOD   $142,994                  $137,688
NET LOSS                           (1,648)                   (1,560)
CASH DIVIDENDS DECLARED:
    Common Stock                   22,455                    13,060
    Preferred Stock                    53                        53
                                       --                        --

BALANCE AT END OF PERIOD         $118,838                  $123,015
                                 ========                  ========

The common stock of PSO is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                           March 31, 2002     December 31, 2001
                                           --------------     -----------------
                                                     (in thousands)

ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                  $1,040,043          $1,034,711
   Transmission                                   430,395             427,110
   Distribution                                   989,002             972,806
   General                                        200,141             203,572
   Construction Work in Progress                   40,799              56,900
                                                   ------              ------
        Total Electric Utility Plant            2,700,380           2,695,099
   Accumulated Depreciation and Amortization    1,199,198           1,184,443
                                                ---------           ---------
        NET ELECTRIC UTILITY PLANT              1,501,182           1,510,656
                                                ---------           ---------

OTHER PROPERTY AND INVESTMENTS                     41,425              41,020
                                                   ------              ------

LONG-TERM ENERGY TRADING CONTRACTS                 22,890              55,215
                                                   ------              ------

CURRENT ASSETS:
   Cash and Cash Equivalents                        7,841               5,795
   Accounts Receivable:
      Customers                                    37,214              31,100
      Affiliated Companies                          8,524              10,905
   Fuel - at LIFO costs                            21,074              21,559
   Materials and Supplies - at average costs       38,616              36,785
   Energy Trading Contracts                        37,507             162,200
   Prepayments                                      1,861               2,368
                                                    -----               -----
          TOTAL CURRENT ASSETS                    152,637             270,712
                                                  -------             -------

REGULATORY ASSETS                                  29,791              35,004
                                                   ------              ------

DEFERRED CHARGES                                   25,831               5,290
                                                   ------               -----

          TOTAL ASSETS                         $1,773,756          $1,917,897
                                               ==========          ==========

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                    March 31, 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
   Retained Earnings                                       118,838              142,994
                                                           -------              -------
        Total Common Shareholder's Equity                  456,068              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                                          345,205              345,129
                                                           -------              -------

           TOTAL CAPITALIZATION                            881,556              905,636
                                                           -------              -------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                      106,000              106,000
   Advances from Affiliates                                186,997              123,087
   Accounts Payable - General                               46,658               72,759
   Accounts Payable - Affiliated Companies                  35,531               40,857
   Customers Deposits                                       21,547               21,041
   Over-Recovered Fuel Costs                                11,100                8,720
   Taxes Accrued                                            27,557               18,150
   Interest Accrued                                         11,365                7,298
   Energy Trading Contracts                                 43,403              167,658
   Other                                                     9,637               12,296
                                                             -----               ------

           TOTAL CURRENT LIABILITIES                       499,795              577,866
                                                           -------              -------

DEFERRED INCOME TAXES                                      299,232              296,877
                                                           -------              -------

DEFERRED INVESTMENT TAX CREDITS                             33,544               33,992
                                                            ------               ------

REGULATORY LIABILITIES AND DEFERRED CREDITS                 38,469               56,203
                                                            ------               ------

LONG-TERM ENERGY TRADING CONTRACTS                          21,160               47,323
                                                            ------               ------

           TOTAL CAPITALIZATION AND LIABILITIES         $1,773,756           $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)

                                                         Three Months Ended March 31,
                                                                  2002                  2001
                                                                  ----                  ----
                                                                       (in thousands)
<S>                                                        <C>              <C>
OPERATING ACTIVITIES:
   Net Income (Loss)                                       $(1,648)          $ (1,560)
   Adjustments for Noncash Items:
      Depreciation and Amortization                         20,916             19,471
      Deferred Income Taxes                                  1,886              5,750
      Deferred Investment Tax Credits                         (448)              (448)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                             (3,733)            (4,018)
      Fuel, Materials and Supplies                          (1,346)             5,864
      Accounts Payable                                     (31,427)           (35,424)
      Taxes Accrued                                          9,407              4,738
      Deferred Property Taxes                              (21,210)           (20,730)
      Fuel Recovery                                          2,380             (2,724)
   Mark to Market of Energy Trading Contracts                 (104)              -
   Changes in Other Assets                                     765               (832)
   Changes in Other Liabilities                             (4,235)            (3,101)
                                                            ------             ------
           Net Cash Flows Used For Operating Activities    (28,797)           (33,014)
                                                           -------            -------

INVESTING ACTIVITIES:
      Construction Expenditures                            (10,559)           (28,595)
      Other                                                   -                  (359)
                                                             -----               ----
           Net Cash Flows Used For Investing Activities    (10,559)           (28,954)
                                                           -------            -------

FINANCING ACTIVITIES:
      Retirement of Long-term Debt                            -               (20,000)
      Change in Advances From Affiliates (net)              63,910             97,872
      Dividends Paid on Common Stock                       (22,455)           (13,060)
      Dividends Paid on Cumulative Preferred Stock             (53)               (53)
                                                               ---                ---
           Net Cash Flows From Financing Activities         41,402             64,759
                                                            ------             ------

Net Increase in Cash and Cash Equivalents                    2,046              2,791
Cash and Cash Equivalents at Beginning of Period             5,795             11,301
                                                             -----             ------
Cash and Cash Equivalents at End of Period                 $ 7,841          $ 14,092
                                                           =======          ========
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized  amounts was $5,157,000 and $5,736,000
and  for  income  taxes  was   $1,783,000  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

                    FIRST QUARTER 2002 vs. FIRST QUARTER 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.
           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.
<PAGE>
        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
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.
<PAGE>
        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 decreased $12.7 million or 64% for the quarter.  The decrease
resulted primarily from reduced wholesale prices and margins due to a decline in
demand for  electricity  which  resulted  from mild  winter  weather  and a slow
economic recovery.
        Operating  revenues  decreased  22% in  2002  because  of a  significant
decrease  in  wholesale  marketing  and  trading  revenues.  The  changes in the
components of revenues were as follows:
                                Increase (Decrease)
                                      (in millions)         %

         Electricity Marketing
          and Trading*                     $(80.1)        (25)
         Energy Delivery*                    (9.1)        (12)
         Sales to AEP Affiliates             (5.7)        (20)
                                             ----
              Total                        $(94.9)        (22)
                                           ======

         *Reflects  the  allocation  of certain  transmission  and  distribution
         revenues included in bundled retail rates to energy delivery.

     Operating  revenues  decreased  in 2002 as a result  of  reduced  wholesale
prices due to reduced  energy demand as a result of the mild winter  weather and
the slow recovery from the economic recession.
     Operating  expenses  decreased  by 21% in 2002 mostly due to a  significant
decrease in electricity marketing and trading purchases and fuel expense.
                                          Increase (Decrease)
                                          -------------------
                                                (in millions)          %
                                                -------------          -

         Fuel                                        $(29.3)         (25)
         Electricity Marketing and
           Trading Purchases                          (43.7)         (28)
         Purchases from AEP Affiliates                 (5.6)         (40)
         Other Operation                                2.9            7
         Maintenance                                   (3.4)         (22)
         Depreciation and Amortization                  2.0            7
         Taxes Other Than Income Taxes                  0.2            1
         Income Taxes                                  (5.5)         (71)
                                                       ----
              Total                                  $(82.4)         (21)
                                                     ======

        Fuel expense  decreased due to lower natural gas prices as a result of a
mild winter and the slow  recovery from the economic  recession  that started in
the fourth quarter of 2001.
<PAGE>
        A milder  than  normal  winter and  decreasing  purchased  power  prices
resulted in decreases to both  electricity  marketing and trading  purchases and
electricity purchases from AEP affiliates.
        Due to the  acquisition  of Dolet Hills  mining  operation in June 2001,
other operation expense increased in 2002.
        Maintenance expense decreased as a result of costs incurred last year to
restore service and make repairs following a severe ice storm.
        The increase in depreciation and amortization  expense was due primarily
to the acquisition of the Dolet Hills mining operation.
        Income taxes  attributable to operations  decreased due to a significant
decrease in pre-tax income.
        Nonoperating  income  decreased 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 early 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.  Also a
decrease  in  allowance  for  funds  used  during   construction  due  to  lower
construction balances reduced nonoperating income.
<PAGE>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                     Three Months Ended March 31,
                                            2002           2001
                                            ----           ----
                                                     (in thousands)
OPERATING REVENUES:
  Electricity Marketing and Trading     $238,854        $318,986
  Energy Delivery                         68,935          78,057
  Sales to AEP Affiliated                 22,959          28,646
                                          ------          ------
           TOTAL OPERATING REVENUES      330,748         425,689
                                         -------         -------

OPERATING EXPENSES:
   Fuel                                   88,883         118,246
   Purchased Power:
     Electricity Marketing and Trading   111,095         154,795
     AEP Affiliated                        8,441          14,062
   Other Operation                        42,151          39,268
   Maintenance                            11,838          15,236
   Depreciation and Amortization          30,140          28,130
   Taxes Other Than Income Taxes          14,466          14,266
   Income Taxes                            2,234           7,700
                                           -----           -----
           TOTAL OPERATING EXPENSES      309,248         391,703
                                         -------         -------

OPERATING INCOME                          21,500          33,986

NONOPERATING INCOME                          102             834
NONOPERATING EXPENSES                        566             640
NONOPERATING INCOME TAX EXPENSE (CREDIT)      28             (53)

INTEREST CHARGES                          13,818          14,364
                                          ------          ------

NET INCOME                                 7,190          19,869

PREFERRED STOCK DIVIDEND REQUIREMENTS         57              57
                                              --              --

EARNINGS APPLICABLE TO COMMON STOCK       $7,133        $ 19,812
                                          ======        ========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                          Three Months Ended March 31,
                                           2002                   2001
                                           ----                   ----
                                                   (in thousands)

BALANCE AT BEGINNING OF PERIOD             $308,915               $293,989
NET INCOME                                    7,190                 19,869
 DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                             18,964                 18,553
    Preferred Stock                              57                     57
                                                 --                     --

BALANCE AT END OF PERIOD                   $297,084               $295,248
                                           ========               ========

The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                              March 31, 2002   December 31, 2001
                                              --------------   -----------------
                                                       (in thousands)

ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                     $1,440,947         $1,429,356
   Transmission                                      561,473            538,749
   Distribution                                    1,049,876          1,042,523
   General                                           375,438            376,016
   Construction Work in Progress                      38,948             74,120
                                                      ------             ------
        Total Electric Utility Plant               3,466,682          3,460,764
   Accumulated Depreciation and Amortization       1,574,868          1,550,618
                                                   ---------          ---------
        NET ELECTRIC UTILITY PLANT                 1,891,814          1,910,146
                                                   ---------          ---------

OTHER PROPERTY AND INVESTMENTS                        43,561             43,000
                                                      ------             ------

LONG-TERM ENERGY TRADING CONTRACTS                    26,271             63,372
                                                      ------             ------

CURRENT ASSETS:
   Cash and Cash Equivalents                           1,888              5,415
   Accounts Receivable:
      Customers                                       48,236             44,588
      Affiliated Companies                            18,067             12,069
      Allowance for Uncollectible Accounts              (250)               (89)
   Fuel Inventory - at average cost                   69,845             52,212
   Under-recovered Fuel                                 -                 2,501
   Materials and Supplies - at average cost           33,398             32,527
   Energy Trading Contracts                           43,047            186,159
   Prepayments                                        16,127             18,716
                                                      ------             ------
          TOTAL CURRENT ASSETS                       230,358            354,098
                                                     -------            -------

REGULATORY ASSETS                                     49,211             51,989
                                                      ------             ------

DEFERRED CHARGES                                      91,325             67,753
                                                      ------             ------

          TOTAL ASSETS                            $2,332,540         $2,490,358
                                                  ==========         ==========

See Notes to Financial Statements beginning on page L-1.
<PAGE>
              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                March 31, 2002 December 31, 2001
                                                -------------- -----------------
                                                        (in thousands)

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
   Retained Earnings                                   297,084         308,915
                                                       -------         -------
        Total Common Shareowner's Equity               677,744         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                                         494,217         494,688
                                                       -------         -------

        TOTAL CAPITALIZATION                         1,286,665       1,298,967
                                                     ---------       ---------

OTHER NONCURRENT LIABILITIES                            36,197          34,997
                                                        ------          ------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                      595         150,595
   Advances from Affiliates                            272,326         117,367
   Accounts Payable - General                           68,939          71,810
   Accounts Payable - Affiliated Companies              39,186          37,469
   Customer Deposits                                    20,596          19,880
   Taxes Accrued                                        63,253          36,522
   Interest Accrued                                     13,697          13,631
   Energy Trading Contracts                             49,709         192,318
   Over-recovered Fuel                                   7,613            -
   Other                                                20,801          26,166
                                                        ------          ------

        TOTAL CURRENT LIABILITIES                      556,715         665,758
                                                       -------         -------

DEFERRED INCOME TAXES                                  366,113         369,781
                                                       -------         -------

DEFERRED INVESTMENT TAX CREDITS                         47,583          48,714
                                                        ------          ------

REGULATORY LIABILITIES AND DEFERRED CREDITS             14,982          17,828
                                                        ------          ------

LONG-TERM ENERGY TRADING CONTRACTS                      24,285          54,313
                                                        ------          ------

CONTINGENCIES (Note 8)

        TOTAL CAPITALIZATION AND LIABILITIES        $2,332,540      $2,490,358
                                                    ==========      ==========

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)

                                                                  Three Months Ended March 31,
                                                                    2002                  2001
                                                                    ----                  ----
                                                                         (in thousands)
<S>                                                              <C>                 <C>
OPERATING ACTIVITIES:
   Net Income                                                     $ 7,190             $ 19,869
   Adjustments for Noncash Items:
      Depreciation and Amortization                                30,140               28,130
      Deferred Income Taxes                                        (3,930)              (1,930)
      Deferred Investment Tax Credits                              (1,131)              (1,113)
      Mark-to-Market of Energy Trading Contracts                    4,498               (5,316)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                    (9,485)              21,669
      Fuel, Materials and Supplies                                (18,504)                (662)
      Accounts Payable                                             (1,154)             (49,324)
      Taxes Accrued                                                26,731               32,119
      Deferred Property Taxes                                     (27,217)             (24,636)
      Fuel Recovery                                                10,114               (6,637)
   Change in Other Assets                                          19,981               (1,391)
   Change in Other Liabilities                                     (2,009)             (13,280)
                                                                   ------              -------
           Net Cash Flows From (Used For) Operating Activities     22,700               (2,502)
                                                                   ------               ------

INVESTING ACTIVITIES:
      Construction Expenditures                                   (11,715)             (21,638)
      Other                                                          -                     326
                                                                     ----                  ---
           Net Cash Flows Used For Investing Activities           (11,715)             (21,312)
                                                                  -------              -------

FINANCING ACTIVITIES:
      Retirement of Long-term Debt                               (150,450)                (450)
      Change in Advances from Affiliates (net)                    154,959               43,482
      Dividends Paid on Common Stock                              (18,964)             (18,553)
      Dividends Paid on Cumulative Preferred Stock                    (57)                 (57)
                                                                      ---                  ---
           Net Cash Flows From (Used For) Financing Activities    (14,512)              24,422
                                                                  -------               ------

Net Increase (Decrease) in Cash and Cash Equivalents               (3,527)                 608
Cash and Cash Equivalents at Beginning of Period                    5,415                1,907
                                                                    -----                -----
Cash and Cash Equivalents at End of Period                        $ 1,888               $2,515
                                                                  =======               ======
</TABLE>
Supplemental Disclosure:
Cash  paid  for  interest  net  of  capitalized   amounts  was  $10,203,000  and
$13,877,000 and for income taxes was $8,581,000 and $3,164,000 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
            --------------------------------------------------------
                    FIRST QUARTER 2002 vs. FIRST QUARTER 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 SPP (Southwest Power Pool) 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.  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.
         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 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.
        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.
<PAGE>
        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  "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 $3.1 million or 348% for the quarter. This increase
is due mostly to  significant  decreases  in both average unit costs of fuel and
average costs of purchased power.
        Overall  operating  revenues  decreased $53.8 million for the quarter as
shown below:
                                   Increase (Decrease)
                                         (in millions)         %

         Electricity Marketing
          and Trading*                       $(100.0)        (66)
         Energy Delivery*                        2.0           5
         Sales to AEP Affiliates                44.2         N.M.
                                                ----
              Total                          $ (53.8)        (28)
                                             =======

         *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 $100.0 million as a
result of several  factors,  including  the  elimination  of retail sales in the
ERCOT as of January 1st, 2002, a decrease in energy  trading,  and a milder than
normal winter.  Sales to AEP affiliates  increased $44.2 million due to revenues
to the newly-created affiliated REP.
        Due mostly to a decrease in fuel expense and  electricity  marketing and
trading  purchases,  operating  expenses declined $59.5 million.  Changes in the
components of operating expenses are shown below:

                                          Increase (Decrease)
                                                (in millions)         %

         Fuel                                       $(34.9)         (58)
         Electricity Marketing and
           Trading Purchases                         (17.2)         (28)
         Purchases from AEP Affiliates                (8.8)         (43)
         Other Operation                              (1.6)          (6)
         Maintenance                                  (0.2)          (5)
         Depreciation and Amortization                (0.2)          (2)
         Taxes Other Than Income Taxes                 0.3            4
         Income Taxes                                  3.1          N.M.
                                                       ---
              Total                                 $(59.5)         (31)
                                                    ======

         N.M. = Not Meaningful

        Although  there was only a slight  decrease in the  consumption of fuel,
fuel  expense  decreased  significantly  due mostly to a decrease in the average
unit cost of fuel as a result of lower spot market natural gas prices.
        A milder than normal  winter  coupled with  decreasing  purchased  power
prices lead to a decrease in both  electricity  marketing and trading  purchases
and electricity purchases from AEP affiliates.
        A decrease  in other  operation  expense was the result of a decrease in
ERCOT transmission-related fees.
        Income taxes  attributable to operations  increased due to a significant
increase in pre-tax income.
        A  decrease  in  nonoperating   income  was  caused  by  a  decrease  in
mark-to-market financial energy trading losses.
<PAGE>
                          WEST TEXAS UTILITIES COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                        Three Months Ended March 31,
                                            2002              2001
                                            ----              ----
                                                (in thousands)
OPERATING REVENUES:
   Electricity Marketing and Trading     $ 50,365          $150,341
   Energy Delivery                         40,629            38,642
   Sales to AEP Affiliates                 50,242             6,023
                                           ------             -----
        Total Operating Revenues          141,236           195,006
                                          -------           -------

OPERATING EXPENSES:

   Fuel                                    24,980            59,905
   Purchased Power:
     Electricity Marketing and Trading     44,123            61,300
     AEP Affiliates                        11,650            20,392
   Other Operation                         24,170            25,756
   Maintenance                              4,356             4,562
   Depreciation and Amortization           11,569            11,771
   Taxes Other Than Income Taxes            6,300             6,038
   Income Taxes (Credit)                    2,943              (110)
                                            -----              ----
           Total Operating Expenses       130,091           189,614
                                          -------           -------

OPERATING INCOME                           11,145             5,392

NONOPERATING INCOME (LOSS)                 (1,488)            2,045

NONOPERATING EXPENSES                       1,372               332

NONOPERATING INCOME TAX EXPENSE (CREDIT)     (989)              282

INTEREST CHARGES                            5,282             5,932
                                            -----             -----
NET INCOME                                  3,992               891
PREFERRED STOCK DIVIDEND REQUIREMENTS          26                26
                                               --                --

EARNINGS APPLICABLE TO COMMON STOCK        $3,966             $ 865
                                           ======             =====

                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                       Three Months Ended March 31,
                                        2002                     2001
                                        ----                     ----
                                             (in thousands)
BALANCE AT BEGINNING OF PERIOD      $105,970                  $122,588
NET INCOME                             3,992                       891

DEDUCTIONS:
   Cash Dividends Declared:
    Common Stock                       6,749                     7,206
    Preferred Stock                       26                        26
                                          --                        --

BALANCE AT END OF PERIOD            $103,187                  $116,247
                                    ========                  ========

The common stock of the Company is wholly owned by AEP.

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

                                            March 31, 2002  December 31, 2001
                                            --------------  -----------------
                                                         (in thousands)

ASSETS
------
ELECTRIC UTILITY PLANT:
   Production                                  $  442,078        $  443,508
   Transmission                                   253,347           250,023
   Distribution                                   437,265           431,969
   General                                        108,580           112,797
   Construction Work in Progress                   18,749            22,575
                                                   ------            ------
        Total Electric Utility Plant            1,260,019         1,260,872
   Accumulated Depreciation and Amortization      547,380           546,162
                                                  -------           -------
       NET ELECTRIC UTILITY PLANT                 712,639           714,710
                                                  -------           -------

OTHER PROPERTY AND INVESTMENTS                     25,634            24,933
                                                   ------            ------

LONG-TERM ENERGY TRADING CONTRACTS                 14,120            21,532
                                                   ------            ------

CURRENT ASSETS:
   Cash and Cash Equivalents                          556             2,454
   Accounts Receivable:
      Customers                                    30,945            18,720
      Affiliated Companies                         24,928             8,656
      Allowance for Uncollectible Accounts           (237)             (196)
   Fuel - at average cost                           8,977             8,307
   Materials and Supplies - at average cost        11,426            11,190
   Under-recovered Fuel Costs                      33,419            32,791
   Energy Trading Contracts                        25,383            63,252
   Prepayments and Other Current Assets               453               966
                                                      ---               ---
          TOTAL CURRENT ASSETS                    135,850           146,140
                                                  -------           -------

REGULATORY ASSETS                                  11,786            13,659
                                                   ------            ------

DEFERRED CHARGES                                   15,358             2,446
                                                   ------             -----

          TOTAL ASSETS                           $915,387          $923,420
                                                 ========          ========

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

                                        March 31, 2002  December 31, 2001
                                        --------------  -----------------
                                                  (in thousands)

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
   Retained Earnings                            103,187         105,970
                                                -------         -------
        Total Common Shareowner's Equity        242,637         245,420
Cumulative Preferred Stock Not Subject to
  Mandatory Redemption                            2,482           2,482
Long-term Debt                                  220,998         220,967
                                                -------         -------

        TOTAL CAPITZALIZATION                   466,117         468,869
                                                -------         -------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year            35,000          35,000
   Advances from Affiliates                      89,168          50,448
   Accounts Payable - General                    17,958          33,782
   Accounts Payable - Affiliated Companies       26,263          11,388
   Customer Deposits                               -              4,191
   Taxes Accrued                                 21,563          17,358
   Interest Accrued                               2,832           1,244
   Energy Trading Contracts                      21,843          65,414
   Other                                         13,875          12,001
                                                 ------          ------

        TOTAL CURRENT LIABILITIES               228,502         230,826
                                                -------         -------

DEFERRED INCOME TAXES                           145,078         145,049
                                                -------         -------

DEFERRED INVESTMENT TAX CREDITS                  22,463          22,781
                                                 ------          ------

LONG-TERM ENERGY TRADING CONTRACTS               12,183          18,455
                                                 ------          ------

REGULATORY LIABILITIES AND DEFERRED CREDITS      41,044          37,440
                                                 ------          ------

CONTINGENCIES (Note 8)

        TOTAL CAPITALIZATION AND LIABILITIES   $915,387        $923,420
                                               ========        ========

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

                                                                 Three Months Ended March 31,
                                                                       2002             2001
                                                                       ----             ----
                                                                           (in thousands)
<S>                                                                 <C>               <C>
OPERATING ACTIVITIES:
   Net Income                                                       $ 3,992             $ 891
   Adjustments for Noncash Items:
      Depreciation and Amortization                                  11,569            11,771
      Deferred Income Taxes                                            (226)               85
      Deferred Investment Tax Credits                                  (318)             (318)
   Mark-to-Market of Energy Trading Contracts                          (664)           (2,129)
   Changes in Certain Assets and Liabilities:
      Accounts Receivable (net)                                     (28,456)           12,381
      Fuel, Materials and Supplies                                     (906)           (1,051)
      Accounts Payable                                                 (949)          (15,986)
      Taxes Accrued                                                   4,205             5,044
      Fuel Recovery                                                    (628)           (1,843)
   Deferred Property Taxes                                           (9,525)           (8,616)
   Change in Other Assets                                            (4,118)            3,049
   Change in Other Liabilities                                         (288)            2,281
                                                                       ----             -----
           Net Cash Flows From (Used For) Operating Activities      (26,312)            5,559
                                                                    -------             -----

INVESTING ACTIVITIES:
      Construction Expenditures                                      (7,531)          (10,762)
      Other                                                            -                -
                                                                       ----            ------
           Net Cash Flows Used For Investing Activities              (7,531)          (10,762)
                                                                     ------           -------

FINANCING ACTIVITIES:
      Change in Advances from Affiliates (net)                       38,720             9,238
      Dividends Paid on Common Stock                                 (6,749)           (7,206)
      Dividends Paid on Cumulative Preferred Stock                      (26)              (26)
                                                                        ---               ---
           Net Cash Flows From (Used For) Financing Activities       31,945             2,006
                                                                     ------             -----

Net Decrease in Cash and Cash Equivalents                            (1,898)           (3,197)
Cash and Cash Equivalents at Beginning of Period                      2,454             6,941
                                                                      -----             -----
Cash and Cash Equivalents at End of Period                            $ 556           $ 3,744
                                                                      =====           =======
</TABLE>
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized  amounts was $2,097,000 and
$2,162,000 and for income taxes was  ($1,575,000)  and  ($2,957,000) in 2002 and
2001, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
                          NOTES TO FINANCIAL STATEMENTS
                                 MARCH 31, 2002
                                   (UNAUDITED)

The notes to financial statements are a combined presentation for AEP and its
subsidiary registrants as follows:
<TABLE>
<CAPTION>
                         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.           Rate Matters                   AEP, WTU

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

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

7.           Financing and Related
                Activities                  AEP, CPL, 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.

               We recently  began  testing  for  goodwill  impairment  of our UK
          operations  as  required  by SFAS 142 and will  complete  the  initial
          testing  in the  second  quarter  of  2002.  If after  completing  our
          transition  testing we determine  that any  goodwill is impaired,  the
          transitional  impairment  loss from the  adoption  of SFAS 142 will be
          reported as a cumulative effect of an accounting change retroactive to
          January 1, 2002.

               Also see "Possible  Divestitures" in Management's  Discussion and
          Analysis for related discussion of potential material losses.

               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.

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

          Goodwill

               The  changes in the  carrying  amount of  goodwill  for the three
          months ended March 31, 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              $1,169                  $1,546
       Goodwill acquired                      2              -                -                          2
       Goodwill assigned from
        purchase price allocation
        for recent prior period
        acquisitions                         77              -                -                         77
       Non-transitional
        impairment loss                       -              -                 (12)                    (12)
       Foreign currency exchange
         rate changes                         -              -                 (22)                    (22)
                                              -              -                 ---                     ---
       Balance March 31, 2002              $419            $37              $1,135                  $1,591
                                           ====            ===              ======                  ======
</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.

               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.
<TABLE>
<CAPTION>
       Net Income                                                        Three Months Ended March 31,
                                                                           2002                  2001
                                                                           ----                  ----
                                                                              (in millions)
<S>                                                                          <C>                 <C>
       Reported Net Income                                                   $181                $266
       Add back: Goodwill amortization                                         -                    9
       Add back amortization for intangibles with
        indefinite lives under SFAS 142                                        -                    2
                                                                               --                   -
       Adjusted Net Income                                                   $181                $277
                                                                             ====                ====
</TABLE>
<TABLE>
<CAPTION>

       Earnings Per Share (Basic and Dilutive)                           Three Months Ended March 31,
                                                                           2002                  2001
                                                                           ----                  ----
<S>                                                                        <C>                   <C>
       Reported Earnings per Share                                         $0.56                 $0.83
       Add back: Goodwill amortization                                       -                    0.03
       Add back amortization for intangibles with
        indefinite lives under SFAS 142                                      -                     -
                                                                             ---                   ---
       Adjusted Earnings per Share                                         $0.56                 $0.86
                                                                           =====                 =====
</TABLE>
<PAGE>
       Acquired Intangible Assets

               Acquired  intangible  assets  subject  to  amortization  are  $31
        million at March 31, 2002 and $20  million at  December  31, 2001 net of
        accumulated  amortization.  The gross  carrying  amount and  accumulated
        amortization by major asset class are:
<TABLE>
<CAPTION>
                                                           March 31, 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                                  $25                     $4                   $24                      $4
       Unpatented Technology                              10                      -                     -                       -
                                                          --                      -                     -                       -
       Totals                                            $35                     $4                   $24                      $4
                                                         ===                     ==                   ===                      ==
</TABLE>
                Amortization of intangible assets was $0.5 million for the three
        months ended March 31, 2002.

                Estimated  aggregate  amortization  expense is $2.2  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 $440  million  and $421  million at March 31,
        2002 and December 31, 2001.

                Fluctuations  in the  carrying  values of the  CitiPower  retail
        supply and  distribution  licenses  since  December  31, 2001  represent
        changes in the foreign currency exchange rate.

3.      ACQUISITIONS AND DISPOSITIONS

                  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.  The acquisition is an addition
         to the growing  energy  trading  operation in Europe based in the U.K.,
         where we now trade power and gas in the U.K., France,  Germany, and the
         Netherlands  and coal  throughout the world.  Results of operations are
         included in the  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.

                  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. This approach satisfies the parties<180>  desire to have
         the  transfer  price  reflect the actual  fair  market  value on a date
         nearer to closing,  and is  consistent  with the  pooling of  interests
         accounting   limitations  imposed  on  AEP  until  June  15,  2002,  in
         connection  with its merger with  Central  and South West Corp.  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
         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.
<PAGE>
4.      RATE MATTERS

            As discussed in Note 5 of the Notes to Financial  Statements  in 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 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.

      Texas Retail Price-to-Beat Rates - Affecting AEP

              The Texas retail electric  providers (REP) for the ERCOT area, CPL
      REP and WTU REP, filed with the PUCT to increase the fuel portion of their
      "price-to-beat" rate. 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.  Any rate adjustment
      approved by the PUCT would be  effective  on June 28, 2002 or a later date
      ordered by the PUCT.

5.      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.

        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.  Per  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. See the 2001 Annual Report for further discussion.

        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.

                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.
<PAGE>
                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  clauses 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.

                 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.  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.

        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  March  31,  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.
<PAGE>
6.      BUSINESS SEGMENTS

                AEP has three business segments:  Wholesale, Energy Delivery and
        Other. The business activities of each of these segments are as follows:

         Wholesale
         o Generation of electricity for sale to retail and wholesale customers,
         o Marketing  and  trading  of  electricity  and gas  worldwide.
         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 three months ended March
         31,  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
        March 31, 2002                                                             (in millions)
<S>                                                             <C>       <C>           <C>        <C>             <C>
        Revenues from:
          External customers                                    $12,115   $   798       $  501     $   -           $13,414
          Other operating segments                                  658         1          243        (902)             -
        Segment EBIT                                                238       204           65         -               507
        Total assets                                             34,248    12,958        6,096      (3,149)  (a)    50,153

        (a) Reconciling adjustments for Total Assets:
            Eliminate intercompany balances                                                         (3,855)
            Corporate assets                                                                           706
                                                                                                    ------
                                                                                                    (3,149)
        March 31, 2001 Revenues from:
          External customers                                     12,878       789          568         -            14,235
          Other operating segments                                  192                               (192)
        Segment EBIT                                                352       245          113          (5)            705
        Total assets                                             25,392    13,405        8,113                      46,910
</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>
                                                   Three Months Ended                          Three Months Ended
                                                     March 31, 2002                              March 31, 2001
                                       Revenues                                     Revenues
                                       From                                         From
                                       External     Segment                         External     Segment
                                       Customers    EBIT         Total Assets       Customers    EBIT          Total Assets
        Wholesale Segment                                    (in thousands)                              (in thousands)
<S>                                     <C>            <C>       <C>                 <C>           <C>          <C>
        APCo                            $1,300,161     $58,987   $3,103,614          $1,822,030    $62,766      $3,684,595
        CPL                                291,096      39,546     2,921,932            493,082     52,080       2,945,850
        CSPCo                              846,767      54,615     2,194,995          1,026,577     60,163       2,624,371
        I&M                                964,222       4,747     3,585,106          1,213,601     39,733       4,172,159
        KPCo                               316,179       5,757       656,456            422,830      1,021         840,123
        OPCo                             1,241,826     100,473     3,451,859          1,567,816     69,236       4,193,940
        PSO                                196,118       1,063       838,987            307,722        713         845,308
        SWEPCo                             261,813       9,637     1,142,945            347,632     17,220       1,146,835
        WTU                                100,607       5,818       392,701            156,364     (2,546)        442,070
</TABLE>
<TABLE>
<CAPTION>
                                       Revenues                                     Revenues
                                       From                                         From
                                       External      Segment                        External     Segment
                                       Customers     EBIT        Total Assets       Customers    EBIT          Total Assets
        Energy Delivery Segment                         (in thousands)                              (in thousands)
<S>                                     <C>           <C>          <C>                <C>           <C>            <C>
        APCo                            $154,995      $58,694      $2,448,468         $152,097      $63,189        $2,906,810
        CPL                              112,127       26,527       2,098,569          110,330       32,372         2,072,634
        CSPCo                            102,548       11,688       1,234,685           98,996       14,762         1,333,956
        I&M                               74,537       35,321       1,618,241           77,937       36,114         1,704,121
        KPCo                              35,129       16,500         635,780           36,327       16,636           701,388
        OPCo                             141,760       23,943       1,924,868          131,849       34,077         2,019,304
        PSO                               51,732        5,263         934,769           48,417        6,344           945,599
        SWEPCo                            68,935       13,633       1,189,595           78,057       24,660         1,058,616
        WTU                               40,629        5,408         522,686           38,642        9,540           486,649
</TABLE>
<TABLE>
<CAPTION>
                                       Revenues                                     Revenues
                                       From                                         From
        Registrant Subsidiaries        External                  Total Assets       External
        Company Total                  Customers    EBIT                            Customers    EBIT          Total Assets
                                                        (in thousands)                              (in thousands)
<S>                                     <C>           <C>          <C>               <C>           <C>             <C>
        APCo                            $1,455,156    $117,681     $5,552,082        $1,974,127    $125,955        $6,591,405
        CPL                                403,223      66,073      5,020,501           603,412      84,452         5,018,484
        CSPCo                              949,315      66,303      3,429,680         1,125,573      74,925         3,958,327
        I&M                              1,038,759      40,068      5,203,347         1,291,538      75,847         5,876,280
        KPCo                               351,308      22,257      1,292,236           459,157      17,657         1,541,511
        OPCo                             1,383,586     124,416      5,376,727         1,699,665     103,313         6,213,244
        PSO                                247,850       6,326      1,773,756           356,139       7,057         1,790,907
        SWEPCo                             330,748      23,270      2,332,540           425,689      41,880         2,205,451
        WTU                                141,236      11,226        915,387           195,006       6,994           928,719
</TABLE>
<PAGE>
7.      FINANCING AND RELATED ACTIVITIES

               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 5).  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

               A subsidiary  of AEP also  increased  borrowing on its  revolving
        credit agreement by $73 million.  The agreement has a variable  interest
        rate and is due in 2003.

               The following table lists long-term debt  retirements  during the
first quarter of 2002 by the registrant subsidiaries:
<TABLE>
<CAPTION>
                                                            Principal
                                   Type                       Amount    Interest  Due
        Company                    of Debt                    Retired     Rate    Date
        -------                    -------                  ----------- --------  ----
                                                        (in millions)   (%)
<S>                                                            <C>      <C>       <C>
        CPL                        Senior Unsecured Notes      $150     Variable  2002
        SWEPCo                     Senior Unsecured Notes       150     Variable  2002
        Non-Registrant AEP Subs.   Notes Payable                 12     Variable  2002-2007
                                                               ----
                                                               $312
</TABLE>
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. Those states could face 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. AEP subsidiaries and other utilities requested that
        the D.C. Circuit Court review this ruling.

               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 on May
        1, 2002 advising  that no changes in the growth  factors used to set the
        NOx budgets were warranted.

               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.
<PAGE>
               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 March 31, 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                         140
               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 is the nominal owner of the cushion
        gas has entered into a financing arrangement with a group of banks which
        purports to provide rights to the cushion gas in certain  circumstances.
        The banks  consented to our use of the cushion gas  coextensive  for the
        term of the  lease of the  Bammel  gas  storage  facility.  We have been
        informed by the banks of Bammel Trust's default under the terms of their
        financing  agreement and it is not clear what, if any,  rights the banks
        will assert with respect to the cushion gas.

               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
<PAGE>
               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 Bammel Trust's default under the cushion gas
        financing  agreement,  our future results of operations,  cash flows and
        possibly financial condition could be adversely impacted.

        California Energy Market Investigation by FERC - Affecting AEP

               On February  13,  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 13, 2002 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  requires 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  intends  to fully
        comply with the order by the May 22, 2002 response date.

        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 ended
March 31, 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.  As of April 30,
2002, the ratings of AEP's commercial paper, the registrant  subsidiaries' first
mortgage  bonds  and  the  senior  unsecured  debt  of AEP  and  its  registrant
subsidiaries  is unchanged from year end.  However,  on April 19, 2002,  Moody's
Investors  Service  announced that AEP and five of its  registrant  subsidiaries
(CPL,  CSPCo,  OPCo,  SWEPCo and WTU) had been placed on credit rating watch for
possible downgrade.
        The review of the  companies'  debt  position and credit rating is being
completed in anticipation of corporate  separation.  We are working with Moody's
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.
        Cash from operations and short-term  borrowings  provide working capital
and meet other short-term cash needs. We generally use short-term  borrowings to
fund property  acquisitions and construction  until long-term funding mechanisms
are arranged.  Sources of long-term  funding  include  issuance of common stock,
preferred stock or long-term debt and sale-leaseback or leasing  agreements.  We
operate a money pool and sell accounts  receivables to provide liquidity for the
domestic  electric  subsidiaries.  Short-term  borrowings  are  supported  by  a
bank-sponsored  receivables  purchase agreement,  a term loan facility and three
revolving credit agreements.
        During the first quarter of 2002 cash flow from  operations was negative
$14 million,  including  $181  million  from net  income and $290  million  from
depreciation,  amortization and deferred taxes. Capital  expenditures  including
acquisitions  were $378 million and dividends on common stock were $193 million.
Cash from the  issuance of $797 million of  transition  funding  bonds  provided
funds to cover the operating funds  deficiency,  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 second quarter of
2002.  Long-term  funding  arrangements  are  often  complex  and  take  time to
complete.
<PAGE>
        As discussed in the annual  report,  we filed with the SEC in April 2002
for  authorization  to issue a combination of up to $3 billion in equity or debt
to improve our financial  condition as measured by our debt to equity ratio.  We
currently  anticipate  an equity  offering  between $1 billion and $1.5 billion.
This  issuance  proposes  to  include  AEP  common  stock  and  other  equity or
convertible debt instruments.
        Total consolidated plant and property additions including capital leases
for the first quarter  period were $354 million.  The following  table shows the
plant and property additions by certain registrant subsidiaries:

        Company                     Amount
        -------                     ------
                                (in millions)
        APCo                         $63
        CPL                           21
        I&M                           27
        OPCo                          66
        SWEPCo                        12

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 particular,  we have recently 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.
         Other investments and assets being evaluated for potential  disposition
include:
o        SEEBOARD  and  CitiPower,   our  energy   delivery  and  retail  supply
         businesses in the UK and Australia. In connection with our evaluations,
         we have  retained  investment  advisors and are  assessing the relative
         interests  of  several   strategic  and   financial   buyers  of  these
         operations.
                 At SEEBOARD, we have provided interested parties an information
         memorandum  and,  based  upon their  initial  level of  interest,  have
         provided some of those parties the  opportunity to pursue more detailed
         due  diligence  procedures.  We expect to  receive  offers  from  these
         parties to purchase SEEBOARD that are capable of acceptance late in the
         second  quarter.  At  CitiPower,  we have  distributed  an  information
         memorandum and expect to receive similar offers late in June.
o        our  power  generation  interests  in Medway  Power in the UK,  Nanyang
         Electric in China, Pacific Hydro in Australia, and certain cogeneration
         facilities  in the US, our joint  investment in power  distribution  in
         Brazil, and our domestic telecommunications assets.

         A recommendation,  if one is proposed by management,  to dispose of any
of these  investments will be subject to the approval and authority of our Board
of  Directors.  The  ultimate  timing  of a  recommendation  to our  Board for a
disposition  of one or more of these  assets will depend upon market  conditions
and the value of any  buyer's  proposal  to us. If,  based on the outcome of our
evaluations,  our  recommendation  to and  approval  of our Board,  we choose to
dispose of these assets, we would expect to realize  non-recurring losses in the
aggregate  that  will  have a  material  impact on our  results  of  operations.
<PAGE>
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
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  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 an
RTO. 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
competition  and reliability of electric  service.  In May 2002 AEP announced an
agreement with the PJM  Interconnection to pursue terms for participation in its
RTO. Final agreements are expected to be negotiated.
         Management  is unable to  predict  the  outcome  of these  transmission
regulatory  actions and  proceedings or their impact on the timing and operation
of RTOs, our transmission operations or results of operations and cash flows.
OTHER MATTERS
Industry Restructuring
         As discussed in Note 5 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 Ohio,
Michigan and  Virginia  virtually  all  customers  continue to receive  electric
generation,  transmission and distribution  services from our electric operating
companies.
         In the Texas  jurisdiction  competition began in the ERCOT area but was
delayed in the SPP area.
         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.
<PAGE>
         Beginning  January  1, 2002,  fuel costs 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 beginning in 2002.
         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.  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.
<PAGE>
        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. Those states could face
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.  AEP subsidiaries and other utilities
requested that the D.C. Circuit Court review this ruling.
        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
on May 1, 2002  advising  that no changes in the growth  factors used to set the
NOx budgets were warranted.
        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.
<PAGE>
        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 March 31, 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 is the nominal owner of
the cushion gas has entered into a financing  arrangement  with a group of banks
which  purports to provide  rights to the cushion gas in certain  circumstances.
The banks  consented to our use of the cushion gas  coextensive  for the term of
the lease of the Bammel gas storage facility. We have been informed by the banks
of Bammel Trust's default under the terms of their financing agreement and it is
not clear what, if any, rights the banks will assert with respect to the cushion
gas.
<PAGE>
        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.
           If there are any adverse  unforeseen  developments  in the bankruptcy
proceeding  or in  Bammel  Trust's  default  under  the  cushion  gas  financing
agreement,  our future results of operations,  cash flows and possibly financial
condition could be adversely impacted.

California Energy Market Investigation by FERC - Affecting AEP
        On February 13, 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 13, 2002 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 requires 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  intends to fully comply with the order by the May 22, 2002  response
date.
Other
        AEP and its  subsidiary  registrants  continue to be involved in certain
other matters discussed in the 2001 Annual Report.
<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 March 31, 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 at:
              March 31,        December 31,
               2002               2001
               ----               ----
          High Average Low   High Average Low
           (in millions)      (in millions)

AEP        $24    $16   $8    $28    $14   $5

APCo         4      2    1      4      1    -
CPL          -      -    -      3      1    -
CSPCo        3      1    1      2      1    -
I&M          3      1    1      3      1    -
KPCo         1      1    -      1      -    -
OPCo         4      2    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 $657 million at March
31, 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
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 March 31, 2002. At March 31, 2002 approximately 7% 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:
March 31, 2002
                                        (in millions)
AAA/Exchanges                $  1           $ -            $  1
AA                            104             39            143
A                             304             14            318
BBB                         1,021            260          1,281
Below Investment
  Grade                        94             43            137
                           -------          ----            ---
  Total                    $1,524           $356          $1,880
                           ======           ====          ======

           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 March 31, 2002 and  December  31, 2001 were $230 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 first  quarter of 2002  resulted in an
unrealized  increase  in  revenues  of $43  million.  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).
                                                   March 31,
                                                   ---------
                                                      2002
                                                      ----
                                                 (in millions)
Revenues (including mark-to-market
 adjustment)                                         $13,414
Fuel and Purchased Energy Expense                     11,307
                                                     -------
Net Revenues                                         $ 2,107
                                                     =======
Mark-to-Market Revenues on Open Trading Positions        $47*
                                                         ===
Percentage of Net Revenues Represented by
 Mark-to-Market on Open Trading Positions                 2%
                                                          ==
*Excludes reversal of $266 million of mark to market for contracts that
 settled in the 1st quarter of 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 March
31, 2002 of $355 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
                                                   March 31,     December 31,
                                                -------------   ------------
                                                        2002          2001
                                                        ----          ----
                                                (in millions)  (in millions)
Energy Trading and Derivative Contracts:
    Current Asset                                   $ 9,327        $ 8,572
    Long-term Asset                                   3,268          2,370
    Current Liability                                (9,231)        (8,311)
    Long-term Liability                              (3,066)        (2,183)
                                                     ------         ------
Net Fair Value of Energy Trading Contracts and
 Derivative Contracts                                   298            448
Less non-trading related derivatives                    (57)           -
                                                        ---            ---
Net Fair Value of Energy Trading Contracts and
 Related Derivatives                                  $ 355          $ 448
                                                      =====          =====

The above net fair value of energy  trading  contracts  and related  derivatives
includes $47 million, at March 31, 2002, in unrealized mark-to-market gains that
are  recognized  in the income  statement  for the quarter ended March 31, 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.
<PAGE>
<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                               (271)       (a)

Adjustments to (gain) Loss for Contracts entered into and
 settled during period                                                                   (16)       (a)

Fair Value of new open contracts when entered into during the period                      34        (b)

Net option premium payments                                                              119

Changes in market value of contracts                                                      41        (c)
                                                                                       -----

Net Fair Value of Energy Trading Contracts and Commodity Derivatives
 at March 31, 2002                                                                     $ 355        (d)
                                                                                       =====
</TABLE>
(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 $271 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)       "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.
(d)     The net change in the fair value of energy  trading  contracts  for 2002
        that  resulted  in a decrease  of $93 million  ($355  million  less $448
        million)  represents  the balance sheet change.  The net  mark-to-market
        gain on energy trading contracts of $47 million represents the impact on
        earnings  related to open trading  contracts  as of March 31, 2002.  The
        difference  is related  primarily  to  settlement  of prior  period open
        energy trading contracts ($266 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>
Energy Trading Contracts
(in thousands)
<TABLE>
<CAPTION>
                                                       APCo            CPL           CSPCo
Net Fair Value of Energy Trading
<S>                                               <C>             <C>            <C>
 Contracts at December 31, 2001                   $ 75,701        $ 3,857        $ 48,449
(Gain) Loss from Contracts
 realized/settled during period                     (7,935)          (388)         (5,212)
Adjustments to (gain) loss for
 Contracts entered into and settled
 during the period                                   1,742             99           1,139
Fair Value of new open Contracts
 when entered into during period                     8,804          1,045           5,752
Net option premium payments                          1,313           -                859
Changes in market value of Contracts                 3,123         (7,221)          4,835
                                                  --------        -------        --------
Net Fair Value of Energy Trading
 Contracts at March 31, 2002                      $ 82,748        $(2,608)       $ 55,822
                                                  ========        =======        ========

Energy Trading Contracts
(in thousands)
                                                       I&M            KPCo           OPCo
Net Fair Value of Energy Trading
 Contracts at December 31, 2001                   $ 61,345        $12,729        $ 65,446
(Gain) Loss from Contracts
 realized/settled during period                     (5,639)        (2,056)         (7,088)
Adjustments to (gain) loss for
 Contracts entered into and settled
 During the period                                   1,232            450           1,549
Fair Value of new open Contracts
 when entered into during period                     6,224          2,272           7,823
Net option premium payments                            929            339           1,168
Changes in market value of Contracts                 1,135          1,263          14,642
                                                   -------        -------        --------
Net Fair Value of Energy Trading
 Contracts at March 31, 2002                      $ 65,226        $14,997        $ 83,540
                                                  ========        =======        ========

Energy Trading Contracts
(in thousands)
                                                       PSO           SWEPCo           WTU
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                  (294)           (339)          (115)
Adjustments to (gain) loss for
 Contracts Entered into and settled
 during period                                         75              87             29
Fair Value of new open Contracts
 when entered into during period                      796             914            310
Net option premium payments                          -               -              -
Changes in market value of Contracts               (7,177)         (8,238)            30
                                                  -------         -------        -------
Net Fair Value of Energy Trading
 Contracts at March 31, 2002                      $(4,166)        $(4,676)       $ 1,169
                                                  =======         =======        =======
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Energy Trading Contract Maturities
                                                            Fair Value of Contracts at March 31, 2002
                                               ------------------------------------------------------------------
                                                                                 Maturities
                                               ------------------------------------------------------
                                                                                (in millions)
AEP Consolidated                               Less than                                In Excess       Total Fair
Source of Fair Value                           1 year        1-3 years     4-5 years    Of 5 years      Value
--------------------                           ------        ---------     ---------    ----------      ---------
<S>                                            <C>           <C>           <C>          <C>             <C>
Prices actively quoted (a)                     $(177)        $ 52          $ -          $ -             $(125)
Prices provided by other external
 Sources (b)                                     280           22            -            -               302
Prices based on models and other
 Valuation methods (c)                            10           89           52           27               178
                                               -----         ----          ---          ---             -----
Total                                          $ 113         $163          $52          $27             $ 355
                                               =====         ====          ===          ===             =====
</TABLE>
<TABLE>
<CAPTION>
Energy Trading Contract Maturities
                                                            Fair Value of Contracts at March 31, 2002
                                               ------------------------------------------------------------------
                                                                                 Maturities
                                               ------------------------------------------------------
                                                                                (in thousands)
                                               Less than                                In Excess       Total Fair
Source of Fair Value                           1 year        1-3 years     4-5 years    Of 5 years      Value
--------------------                           ------        ---------     ---------    ----------      ---------
<S>                                            <C>           <C>           <C>          <C>             <C>
APCo
Prices provided by other
 External Sources (b)                          $20,369       $15,379       $  -         $ -             $35,748
Prices based on models and other
 Valuation methods (c)                           5,054        22,529        11,637       7,780           47,000
                                               -------       -------       -------      ------          -------
  Total                                        $25,423       $37,908       $11,637      $7,780          $82,748
                                               =======       =======       =======      ======          =======

CPL
Prices provided by other
 External Sources (b)                          $(4,081)      $  667        $  -         $ -             $(3,414)
Prices based on models and other
 Valuation methods (c)                          (1,013)         977           505         337               806
                                               --------      ------        ------       -----           -------
  Total                                        $(5,094)      $1,644        $  505       $ 337           $(2,608)
                                               ========      ======        ======       =====           =======

CSP
Prices provided by other
 External Sources (b)                          $14,746       $10,038       $  -         $ -             $24,784
Prices based on models and other
 Valuation methods (c)                           3,659        14,705        7,596        5,078           31,038
                                               -------       -------       ------       ------          -------
  Total                                        $18,405       $24,743       $7,596       $5,078          $55,822
                                               =======       =======       ======       ======          =======

KPCo
Prices provided by other
 External Sources (b)                          $  176        $3,964        $ -          $ -             $ 4,140
Prices based on models and other
 Valuation methods (c)                             44         5,808         3,000        2,005           10,857
                                               ------        ------        ------       ------          -------
  Total                                        $  220        $9,772        $3,000       $2,005          $14,997
                                               ======        ======        ======       ======          =======
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
I&M
<S>                                            <C>           <C>           <C>          <C>             <C>
Prices provided by other
 External Sources (b)                          $21,918       $10,160       $ -          $ -             $32,078
Prices based on models and other
 Valuation methods (c)                           5,438        14,883        7,688        5,139           33,148
                                               -------       -------       ------       ------          -------
  Total                                        $27,356       $25,043       $7,688       $5,139          $65,226
                                               =======       =======       ======       ======          =======

OPCo
Prices provided by other
 External Sources (b)                          $23,307       $14,608       $  -         $ -             $37,915
Prices based on models and other
 Valuation methods (c)                           5,783        21,399        11,053       7,390           45,625
                                               -------       -------       -------      ------          -------
  Total                                        $29,090       $36,007       $11,053      $7,390          $83,540
                                               =======       =======       =======      ======          =======

PSO
Prices provided by other
 External Sources (b)                          $(4,725)      $  464        $  -         $ -             $(4,261)
Prices based on models and other
 Valuation methods (c)                          (1,172)         680           351        236                 95
                                               --------      ------        ------       ----            -------
  Total                                        $(5,897)      $1,144        $  351       $236            $(4,166)
                                               ========      ======        ======       ====            =======

SWEPCo
Prices provided by other
 External Sources (b)                          $(5,338)      $  533        $  -         $ -             $(4,805)
Prices based on models and other
 Valuation methods (c)                          (1,325)         781           403        270                129
                                               --------      ------        ------       ----            -------
  Total                                        $(6,663)      $1,314        $  403       $270            $(4,676)
                                               ========      ======        ======       ====            =======

WTU
Prices provided by other
 External Sources (b)                          $  (667)      $  537        $  -         $ -             $ (130)
Prices based on models and other
 Valuation methods (c)                            (165)         786           406        272             1,299
                                               --------      ------        ------       ----            ------
  Total                                        $  (832)      $1,323        $  406       $272            $1,169
                                               ========      ======        ======       ====            ======
</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>
                                             PART II.  OTHER INFORMATION

Item 5.  Other Information.

AEP and APCo

        Reference  is made to pages 17 and 18 of the Annual  Report on Form 10-K
for the year ended  December  31,  2001 (2001 10-K) for a  discussion  of APCo's
proposed  transmission  facilities.  On April 23, 2002,the Forest Service issued
its Supplemental Draft Environmental Impact Statement (SDEIS). In the SDEIS, the
Forest Service  identified the  Wyoming-Jacksons  Ferry Project as the preferred
alternative.

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

        Reference  is made to page 26 of the 2001 10-K for a  discussion  of the
ozone and particulate  matter National Ambient Air Quality  Standards.  On March
26, 2002,  the U. S. Court of Appeals issued a unanimous  decision  holding that
Federal EPA's promulgation of revised national ambient air quality standards for
fine particulate matter and ozone was not arbitrary and capricious.

Item 6.  Exhibits and Reports on Form 8-K.

        (a)    Exhibits:

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

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

        (b)    Reports on Form 8-K:

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

               No reports on Form 8-K were filed during the quarter ended
        March 31, 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: May 13, 2002