THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND
SUBSIDIARIES IS REQUESTED TO INCLUDED AS PART OF THE FILING.

                    SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549

                                    FORM 10-Q

              [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                  For The Quarterly Period Ended JUNE 30, 2000

              [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                        For The Transition Period from to

Commission             Registrant; State of Incorporation;     I. R. S. Employer
File Number             Address; and Telephone Number         Identification No.
-----------     ---------------------------------------------- -----------------
  1-3525        AMERICAN ELECTRIC POWER COMPANY, INC.                13-4922640
                (A New York Corporation)
                1 Riverside Plaza, Columbus, Ohio  43215
                Telephone (614) 223-1000

  0-18135       AEP GENERATING COMPANY (An Ohio Corporation)         31-1033833
                1 Riverside Plaza, Columbus, Ohio  43215
                Telephone (614) 223-1000

  1-3457        APPALACHIAN POWER COMPANY (A Virginia Corporation)   54-0124790
                40 Franklin Road, Roanoke, Virginia  24011
                Telephone (540) 985-2300

  1-1443        CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600
                539 North Carancahua  Street,
                Corpus Christi,  Texas 78401-2802
                Telephone (361) 881-5300

  1-2680        COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
                1 Riverside Plaza,
                Columbus, Ohio 43215
                Telephone (614) 223-1000

  1-3570        INDIANA MICHIGAN POWER COMPANY
                (An Indiana Corporation)                              35-0410455
                One Summit Square
                P.O. Box 60, Fort Wayne, Indiana  46801
                Telephone (219) 425-2111

  1-6858        KENTUCKY POWER COMPANY (A Kentucky Corporation)       61-0247775
                1701 Central Avenue, Ashland, Kentucky  41101
                Telephone (800) 572-1141

  1-6543        OHIO POWER COMPANY (An Ohio Corporation)              31-4271000
                301 Cleveland Avenue S.W., Canton, Ohio  44701
                Telephone (330) 456-8173

  0-343         PUBLIC SERVICE COMPANY OF OKLAHOMA                    73-0410895
                (An Oklahoma Corporation)
                212 East 6th Street, Tulsa, Oklahoma  74119-1212
                Telephone (918) 599-2000

  1-3146        SOUTHWESTERN ELECTRIC POWER COMPANY                   72-0323455
                (A Delaware Corporation)
                428 Travis Street, Shreveport, Louisiana  71156-0001
                Telephone (318) 673-3000

0-340           WEST TEXAS UTILITIES  COMPANY (A Texas  Corporation)  75-0646790
                301 Cypress Street,
                Abilene,  Texas 79601-5820  Telephone (915)
                674-7000
<PAGE>



AEP  Generating  Company,  Columbus  Southern  Power Company and Kentucky  Power
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, 2000 was 194,103,349.


<PAGE>

<TABLE>
<CAPTION>

                                                                               Page

     Part I.  FINANCIAL INFORMATION
<S>                                                                            <C>
                American Electric Power Company, Inc. and Subsidiary Companies:
                  Consolidated Statements of Income. . . . . . . . . . . . . . A-1
                  Consolidated Statements of Comprehensive Income . .. . . . . A-2
                  Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-3 - A-4
                  Consolidated Statements of Cash Flows. . . . . . . . . . . . A-5
                  Consolidated Statements of Retained Earnings . . . . . . . . A-6
                  Notes to Consolidated Financial Statements . . . . . . . . . A-7 - A-26
                  Management's Discussion and Analysis of Results of
                    Operations and Financial Condition . . . . . . . . . . . . A-27- A-45

                AEP Generating Company:
                  Statements of Income and Statements of Retained Earnings . . B-1
                  Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . B-2 - B-3
                  Statements of Cash Flows . . . . . . . . . . . . . . . . . . B-4
                  Notes to Financial Statements. . . . . . . . . . . . . . . . B-5 - B-6
                  Management's Narrative Analysis of Results of Operations . . B-7 - B-8

                Appalachian Power Company and Subsidiaries:
                  Consolidated Statements of Income and
                    Consolidated Statements of Retained Earnings . . . . . . . C-1
                  Consolidated Balance Sheets. . . . . . . . . . . . . . . . . C-2 - C-3
                  Consolidated Statements of Cash Flows. . . . . . . . . . . . C-4
                  Notes to Consolidated Financial Statements . . . . . . . . . C-5 - C-11
                  Management's Discussion and Analysis of Results of
                    Operations and Financial Condition . . . . . . . . . . . . C-12- C-18

                Central Power and Light Company:
                  Consolidated Statements of Income and
                    Consolidated Statements of Retained Earnings . . . . . . . D-1
                  Consolidated Balance Sheets. . . . . . . . . . . . . . . . . D-2 - D-3
                  Consolidated Statements of Cash Flows. . . . . . . . . . . . D-4
                  Notes to Consolidated Financial Statements . . . . . . . . . D-5 - D-11
                  Management's Discussion and Analysis of Results of
                    Operations and Financial Condition . . . . . . . . . . . . D-12- D-20

                Columbus Southern Power Company and Subsidiaries:
                  Consolidated Statements of Income and
                    Consolidated Statements of Retained Earnings . . . . . . . E-1
                  Consolidated Balance Sheets. . . . . . . . . . . . . . . . . E-2 - E-3
                  Consolidated Statements of Cash Flows. . . . . . . . . . . . E-4
                  Notes to Consolidated Financial Statements . . . . . . . . . E-5 - E-11
                  Management's Narrative Analysis of Results of Operations . . E-12- E-14

                Indiana Michigan Power Company and Subsidiaries:
                  Consolidated Statements of Income and
                    Consolidated Statements of Retained Earnings . . . . . . . F-1
                  Consolidated Balance Sheets. . . . . . . . . . . . . . . . . F-2 - F-3
                  Consolidated Statements of Cash Flows. . . . . . . . . . . . F-4
                  Notes to Consolidated Financial Statements . . . . . . . . . F-5 - F-10
                  Management's Discussion and Analysis of Results of
                    Operations and Financial Condition . . . . . . . . . . . . F-11- F-18

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


     AMERICAN ELECTRIC POWER COMPANY,INC. AND SUBSIDIARY COMPANIES
                                    FORM 10-Q

                       For The Quarter Ended June 30, 2000

                                      INDEX

                                                                             Page
<S>                                                                            <C>

                Kentucky Power Company:
                  Statements of Income and Statements of Retained Earnings . . G-1
                  Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . G-2 - G-3
                  Statements of Cash Flows . . . . . . . . . . . . . . . . . . G-4
                  Notes to Financial Statements. . . . . . . . . . . . . . . . G-5 - G-9
                  Management's Narrative Analysis of Results of Operations . . G-10- G-12

                Ohio Power Company and Subsidiaries:
                  Consolidated Statements of Income and
                    Consolidated Statements of Retained Earnings . . . . . . . H-1
                  Consolidated Balance Sheets. . . . . . . . . . . . . . . . . H-2 - H-3
                  Consolidated Statements of Cash Flows. . . . . . . . . . . . H-4
                  Notes to Consolidated Financial Statements . . . . . . . . . H-5 - H-11
                  Management's Discussion and Analysis of Results of
                    Operations and Financial Condition . . . . . . . . . . . . H-12- H-20

                Public Service Company of Oklahoma

                  Consolidated Statements of Income and
                    Consolidated  Statements of Retained Earnings . . . . .. . I-1
                  Consolidated Balance Sheets . .  . . . . . . . . . . . . . . I-2 - I-3
                  Consolidated Statements of Cash Flows  . . . . . . . . . . . I-4
                  Notes to Consolidated  Financial Statements . . . . . . .. . I-5
                  Management's Discussion and  Analysis of Results of
                    Operations and Financial Condition . . . . . . . . . . . . I-6 - I-7

                Southwestern Electric Power Company:
                  Consolidated Statements of Income and
                    Consolidated Statements of Retained Earnings . . . . . . . J-1
                  Consolidated Balance Sheets. . . . . . . . . . . . . . . . . J-2 - J-3
                  Consolidated Statements of Cash Flows. . . . . . . . . . . . J-4
                  Notes to Consolidated Financial Statements . . . . . . . . . J-5 - J-9
                  Management's Discussion and Analysis of Results of
                    Operations and Financial Condition . . . . . . . . . . . . J-10- J-12

                West Texas Utilities Company:
                  Statements of Income and Statements of Retained Earnings . . K-1
                  Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . K-2 - K-3
                  Statements of Cash Flows . . . . . . . . . . . . . . . . . . K-4
                  Notes to Financial Statements . . . . . . .. . . . . . . . . K-5 - K-7
                  Management's Discussion and Analysis of Results of
                    Operations and Financial Condition . . . . . . . . . . . . K-8 - K-9

     Part II. OTHER INFORMATION
                Item 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1
                Item 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1-II-3
                Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3
                Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3-II-4

     SIGNATURE  .  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-5

            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.
</TABLE>
<PAGE>





     FORWARD-LOOKING INFORMATION

     This report made by American Electric Power Company, Inc. (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:

     - Electric  load and customer  growth.  - Abnormal  weather  conditions.  -
     Available  sources  and  costs  of  fuels.  -  Availability  of  generating
     capacity.

     - The speed and  degree to which  competition  is  introduced  to our power
     generation business. - The structure and timing of a competitive market and
     its  impact on energy  prices or fixed  rates.  - The  ability  to  recover
     stranded  costs  in  connection  with  possible/proposed   deregulation  of
     generation. - New legislation and government regulations.

     - The ability of AEP to  successfully  control its costs.  - The success of
     new business ventures. - International developments affecting AEP's foreign
     investments. - The economic climate and growth in AEP's service territory.

     -  Unforeseen events affecting AEP's restart of Cook Nuclear Plant Unit 1
          which is on   an extended safety related shutdown.
     -  Inflationary trends.
     -  Electricity and gas market prices.
     -  Interest rates - Other risks and unforeseen events.


<PAGE>
<TABLE>
<CAPTION>


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED STATEMENTS OF INCOME

                     (in millions, except per-share amounts)
                                   (UNAUDITED)

                       Three Months Ended Six Months Ended

                                                   June 30,               June 30,
                                           ----------------------  ---------------
                                              2000        1999        2000        1999
                                              ----        ----        ----        ----
REVENUES:
<S>                                          <C>         <C>         <C>         <C>

  Domestic Regulated Electric Utilities. .   $2,582      $2,393      $4,892      $4,640
  Worldwide Electric and Gas Operations. .      586         569       1,321       1,241
                                             ------      ------      ------      ------
          TOTAL REVENUES . . . . . . . . .    3,168       2,962       6,213       5,881
                                             ------      ------      ------      ------

EXPENSES:

  Fuel and Purchased Power . . . . . . . .      976         822       1,806       1,571
  Maintenance and Other Operation. . . . .      716         672       1,405       1,280
  Merger Costs . . . . . . . . . . . . . .      161        -            161        -
  Depreciation and Amortization. . . . . .      257         251         529         500
  Taxes Other Than Income Taxes. . . . . .      169         170         334         347
  Worldwide Electric and Gas Operations. .      584         499       1,219       1,094
                                             ------      ------      ------      ------
          TOTAL EXPENSES . . . . . . . . .    2,863       2,414       5,454       4,792
                                             ------      ------      ------      ------
OPERATING INCOME . . . . . . . . . . . . .      305         548         759       1,089
OTHER INCOME (LOSS), net. . . .. . . . . .       (2)          9          14          21
                                             ------      ------      ------      ------
INCOME BEFORE INTEREST, PREFERRED
  DIVIDENDS AND INCOME TAXES . . . . . . .      303         557         773       1,110

INTEREST AND PREFERRED DIVIDENDS . . . . .      269         246         522         489
                                             ------      ------      ------      ------

INCOME BEFORE INCOME TAXES . . . . . . . .       34         311         251         621

INCOME TAXES . . . . . . . . . . . . . . .       52         121         129         237
                                             ------      ------      ------      ------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM  .      (18)        190         122         384

EXTRAORDINARY GAIN - DISCONTINANCE OF
  SFAS 71 ( INCLUSIVE OF TAX BENEFIT
  OF $8 MILLION ) . . . . . . . . . . .  .        9          -            9          -
                                             ------      ------      ------      ------
NET INCOME (LOSS). . . . . . . . . . . . .   $   (9)     $  190      $  131      $  384
                                             ======      ======      ======      ======

AVERAGE NUMBER OF SHARES OUTSTANDING . . .      322         320         322         320
                                                ===         ===         ===         ===

EARNINGS PER SHARE
   Income (Loss) Before Extraordinary Item   $(0.06)      $0.59      $ 0.38      $ 1.20
   Extraordinary Gain - Discontinance of
     SFAS 71 . . . . . . . . . . . . . . .     0.03          -         0.03          -
                                              ------      ------      ------      ------
   Net Income (Loss) . . . . . . . . . . .   $(0.03)      $0.59       $0.41       $1.20
                                              ======      ======      ======      ======

CASH DIVIDENDS PAID PER SHARE. . . . . . .    $0.60       $0.60       $1.20       $1.20
                                              =====       =====       =====       =====

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

         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)

                       Three Months Ended Six Months Ended

                                                   June 30,               June 30,
                                           ----------------------  ---------------
                                              2000        1999        2000        1999
                                              ----        ----        ----        ----
                                                            (in millions)
<S>                                           <C>         <C>         <C>         <C>
NET INCOME (LOSS). . . . . . . . . . . . .    $ (9)       $190        $ 131       $384
OTHER COMPREHENSIVE INCOME:
  Foreign Currency Translation

    Adjustments. . . . . . . . . . . . . .     (80)          7         (115)       (55)
  Reclassification Adjustment for Loss
    Included in Net Income . . . . . . . .      27          -            20         -
  Unrealized Gains on Securities . . . . .      -            3           -           8
  Minimum Pension Liability. . . . . . . .      (2)         -            (2)        -
                                              ----        ----        -----       ----
COMPREHENSIVE INCOME (LOSS). . . . . . . .    $(64)       $200        $  34       $337
                                              ====        ====        =====       ====

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


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                                June 30,     December 31,
                                                                  2000           1999
                                                              -----------    --------
                                                                    (in millions)
ASSETS
<S>                                                             <C>            <C>
CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . . . .      $   312        $   653
  Accounts Receivable (net). . . . . . . . . . . . . . . .        2,502          2,027
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . .          359            436
  Materials and Supplies . . . . . . . . . . . . . . . . .          464            460
  Accrued Utility Revenues . . . . . . . . . . . . . . . .          430            322
  Energy Trading Contracts . . . . . . . . . . . . . . . .        4,941          1,001
  Prepayments. . . . . . . . . . . . . . . . . . . . . . .          208            175
                                                                -------        -------

          TOTAL CURRENT ASSETS . . . . . . . . . . . . . .        9,216          5,074
                                                                -------        -------

PROPERTY, PLANT AND EQUIPMENT:
  Electric:
    Production . . . . . . . . . . . . . . . . . . . . . .       15,986         15,869
    Transmission . . . . . . . . . . . . . . . . . . . . .        5,563          5,495
    Distribution . . . . . . . . . . . . . . . . . . . . .       10,534         10,432
  Other (including gas and coal mining assets
    and nuclear fuel). . . . . . . . . . . . . . . . . . .        3,995          4,081
  Construction Work in Progress. . . . . . . . . . . . . .        1,211          1,061
                                                                -------        -------
          Total Property, Plant and Equipment. . . . . . .       37,289         36,938
  Accumulated Depreciation and Amortization. . . . . . . .       15,335         15,073
                                                                -------        -------

          NET PROPERTY, PLANT AND EQUIPMENT. . . . . . . .       21,954         21,865
                                                                -------        -------

REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . .        3,629          3,395
                                                                -------        -------

INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS . . . . .          924            862
                                                                -------        -------

GOODWILL (net of amortization) . . . . . . . . . . . . . .        1,422          1,531
                                                                -------        -------

OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . .        3,254          2,992
                                                                -------        -------

            TOTAL. . . . . . . . . . . . . . . . . . . . .      $40,399        $35,719
                                                                =======        =======

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


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                               June 30,      December 31,
                                                                 2000            1999
                                                             ------------    --------
                                                                    (in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S>                                                            <C>             <C>
CURRENT LIABILITIES:
  Accounts Payable . . . . . . . . . . . . . . . . . . . .     $ 1,591         $ 1,280
  Short-term Debt. . . . . . . . . . . . . . . . . . . . .       4,116           3,012
  Preferred Stock Due Within One Year. . . . . . . . . . .          18            -
  Long-term Debt Due Within One Year . . . . . . . . . . .         711           1,367
  Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .         396             601
  Interest Accrued . . . . . . . . . . . . . . . . . . . .         178             142
  Obligations Under Capital Leases . . . . . . . . . . . .         127              91
  Energy Trading Contracts . . . . . . . . . . . . . . . .       4,857             964
  Other. . . . . . . . . . . . . . . . . . . . . . . . . .         681             609
                                                               -------         -------

          TOTAL CURRENT LIABILITIES. . . . . . . . . . . .      12,675           8,066
                                                               -------         -------

LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . .      10,071          10,157
                                                               -------         -------

CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
  PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
  SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
  SUBSIDIARIES . . . . . . . . . . . . . . . . . . . . . .         335             335
                                                               -------         -------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . .       5,086           5,150
                                                               -------         -------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . .         553             580
                                                               -------         -------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . . .         208             213
                                                               -------         -------

DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . . .       1,450             715
                                                               -------         -------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . .       1,604           1,648
                                                               -------         -------

CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . . .         163             182
                                                               -------         -------

CONTINGENCIES (Note 9)

COMMON SHAREHOLDERS' EQUITY:
  Common Stock-Par Value $6.50:
                                2000          1999
                                ----          ----
    Shares Authorized . . . .600,000,000   600,000,000
    Shares Issued . . . . . .330,993,401   330,692,317
    (8,999,992 shares held in treasury). . . . . . . . . .       2,151          2,149
  Paid-in Capital. . . . . . . . . . . . . . . . . . . . .       2,862          2,898
  Accumulated Other Comprehensive Income . . . . . . . . .        (101)            (4)
  Retained Earnings. . . . . . . . . . . . . . . . . . . .       3,342          3,630
                                                               -------        -------

          TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . . .       8,254          8,673
                                                               -------        -------

            TOTAL. . . . . . . . . . . . . . . . . . . . .     $40,399        $35,719
                                                               =======        =======

See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>

<TABLE>
<CAPTION>


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                      Six Months Ended

                                                                          June 30,
                                                                  ----------------
                                                                     2000         1999
                                                                     ----         ----
                                                                       (in millions)
<S>                                                               <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . .$   131        $ 384
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . . . . .    666          625
    Deferred Federal Income Taxes. . . . . . . . . . . . . . . . .     19           41
    Deferred Investment Tax Credits. . . . . . . . . . . . . . . .    (17)         (17)
    Amortization of Deferred Property Taxes. . . . . . . . . . . .     79           80
    Amortization (Deferral) of Cook Plant Restart Costs. . . . . .     20          (60)
    Deferred Costs Under Fuel Clause Mechanisms. . . . . . . . . .   (164)         (58)
    Extraorinary Gain - Discontinuance of SFAS No. 71  . . . . . .     (9)           -
Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . . . . .   (475)         (53)
    Fuel, Materials and Supplies . . . . . . . . . . . . . . . . .     73         (160)
    Accrued Utility Revenues . . . . . . . . . . . . . . . . . . .   (108)         (10)
    Accounts Payable . . . . . . . . . . . . . . . . . . . . . . .    311         (134)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . .   (205)         (74)
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . . .     (4)          38
  Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . .     58          (77)
                                                                  -------        -----
        Net Cash Flows From Operating Activities . . . . . . . . .    375          525
                                                                  -------        -----

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . . . . .   (808)        (732)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    (60)         (37)
                                                                  -------        -----
        Net Cash Flows Used For Investing Activities . . . . . . .   (868)        (769)
                                                                  -------        -----

FINANCING ACTIVITIES:
  Issuance of Common Stock . . . . . . . . . . . . . . . . . . . .     12           64
  Issuance of Long-term Debt . . . . . . . . . . . . . . . . . . .    751          323
  Change in Short-term Debt (net). . . . . . . . . . . . . . . . .  1,104          718
  Retirement of Long-term Debt . . . . . . . . . . . . . . . . . . (1,289)        (400)
  Dividends Paid on Common Stock . . . . . . . . . . . . . . . . .   (419)        (417)
                                                                  -------        -----
        Net Cash Flows From Financing Activities . . . . . . . . .    159          288
                                                                  -------        -----

Effect of Exchange Rate Change on Cash . . . . . . . . . . . . . .     (7)          (4)

Net Increase (Decrease) in Cash and Cash Equivalents . . . . . . .   (341)          40

Cash and Cash Equivalents at Beginning of Period . . . . . . . . .    653          330
                                                                  -------        -----
Cash and Cash Equivalents at End of Period . . . . . . . . . . . .$   312        $ 370
                                                                  =======        =====

Supplemental Disclosure:
  Cash paid for  interest net of  capitalized  amounts was $471 million and $454
  million and for income  taxes was $206  million  and $150  million in 2000 and
  1999, respectively. Noncash acquisitions under capital leases were $50 million
  and $43 million in 2000 and 1999, respectively.

See Notes to Consolidated Financial Statements.

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


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                       Three Months Ended Six Months Ended

                                                   June 30,                June 30,
                                           ----------------------  ----------------
                                              2000        1999        2000        1999
                                              ----        ----        ----        ----
                                                           (in millions)
<S>                                          <C>         <C>         <C>         <C>
BALANCE AT BEGINNING OF PERIOD . . . . . .   $3,580      $3,495      $3,646      $3,507
CONFORMING CHANGE IN ACCOUNTING POLICY
  (Note 2) . . . . . . . . . . . . . . . .      (19)        (16)        (16)        (14)
                                             ------      ------      ------      ------
ADJUSTED BALANCE AT BEGINNING OF PERIOD. .    3,561       3,479       3,630       3,493

NET INCOME (LOSS). . . . . . . . . . . . .       (9)        190         131         384

DEDUCTIONS:

  Cash Dividends Declared - AEP. . . . . .      117         116         233         231
  Cash Dividends Declared - CSW. . . . . .       93          93         186         186
                                             ------      ------      ------      ------

BALANCE AT END OF PERIOD . . . . . . . . .   $3,342      $3,460      $3,342      $3,460
                                             ======      ======      ======      ======

See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>



         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                  JUNE 30, 2000

                                   (UNAUDITED)



1.      GENERAL

               The accompanying  unaudited  consolidated  financial  state-ments
        should  be  read  in   conjunction   with  the  1999  Annual  Report  as
        incorporated  in and  filed  with the Form  10-K.  Certain  prior-period
        amounts   have  been   reclassified   to   conform   to   current-period
        presentation.  In the opinion of  management,  the financial  statements
        reflect all adjustments  (consisting of only normal recurring  accruals)
        which are necessary for a fair presentation of the results of operations
        for interim periods.

2.      MERGER OF AEP AND CSW

               On June  15,  2000,  AEP  merged  with  Central  and  South  West
        Corporation  (CSW) so that CSW became a wholly-owned  subsidiary of AEP.
        Under the terms of the merger  agreement,  approximately  127.9  million
        shares  of AEP  Common  Stock  were  issued  in  exchange  for  all  the
        outstanding  shares of CSW Common Stock based upon an exchange  ratio of
        0.6  share of AEP  Common  Stock  for each  share of CSW  common  stock.
        Following the exchange,  former  shareholders of AEP owned approximately
        61.4 percent of the  corporation,  while former CSW  shareholders  owned
        approximately 38.6 percent of the corporation.

               The  merger  was   accounted  for  as  a  pooling  of  interests.
        Accordingly,  the  consolidated  financial  statements give  retroactive
        effect to the merger,  with all periods  presented as if AEP and CSW had
        always been  combined.  The  combined  financial  statements  include an
        adjustment  to conform CSW's  accounting  for vacation pay accruals with
        AEP's accounting.  The effect of the conforming adjustment was to reduce
        net assets by $19  million at March 31, 2000 and reduce net income by $2
        million for the three  months ended March 31, 2000 and by $3 million and
        $1 million for the years ended December 31, 1999 and 1998, respectively.
        Certain  reclassifications have been made to conform the presentation of
        AEP and CSW.

     CSW's four wholly-owned domestic utility electric subsidiaries are: Central
Power and Light  Company  (CPL),  Public  Service  Company  of  Oklahoma  (PSO),
Southwestern  Electric Power Company  (SWEPCo) and West Texas Utilities  Company
(WTU).  CSW also has the following  principal  subsidiaries:  CSW  International
Inc., CSW Energy, Inc., Seeboard, CSW Credit, Inc., C3 Communications,  Inc. and
CSW Energy Services, Inc.


<PAGE>


               The  following  table sets forth  summary  data for the  separate
        companies and the combined amounts for the following periods:

                       Six Months Ended    Twelve Months Ended

                            June 30,           December 31,
                       -----------------   ----------------
                        2000        1999    1999           1998
                        ----        ----    ----           ----
                                  (in millions)
    Revenues:
        AEP            $3,494     $3,337   $ 6,916      $ 6,397
        CSW             2,719       2,544     5,537        5,482
                       ------      ------   -------      -------
    AEP After Pooling  $6,213     $5,881   $12,453      $11,879
                       ======     ======   =======      =======

    Net Income:
                   AEP              $126       $239      $520         $536
        CSW                 8        148       455          440
        Conforming

           Adjustments     (3)        (3)       (3)          (1)
                         ----       ----      ----         ----
    AEP After Pooling    $131       $384      $972         $975
                         ====       ====      ====         ====

               In  connection  with  the  merger,  $161  million  ($145  million
        after-tax) of  non-recoverable  merger costs were  expensed.  Such costs
        included   transaction  and  transition   costs  not  recoverable   from
        ratepayers.  Also  included  in the merger  costs  were  non-recoverable
        accrued change in control  payments.  Merger  transaction and transition
        costs of $35 million recoverable from customers are deferred pursuant to
        settlement agreements which, among other things, provide for the sharing
        of net merger  savings.  Deferred  merger costs are being amortized over
        five to eight year recovery  periods  depending on the specific terms of
        the  settlement  agreements.  Merger  transition  costs are  expected to
        continue to be incurred  for several  years after the merger and will be
        expensed or deferred for  amortization  as  appropriate.  The settlement
        agreements  provide  for a sharing of net merger  savings  with  certain
        regulated  customers  over  periods of up to eight  years  through  rate
        reductions  effective in the third quarter of 2000.  If realized  merger
        savings are  significantly  less than the merger savings rate reductions
        required by the merger  settlement  agreements in the eight-year  period
        following consummation of the merger, future results of operations, cash
        flows and possibly financial condition could be adversely affected.

        The  divestiture  of 1,904  megawatts  (MW) of  generating  capacity  is
        required  as a  condition  of  regulatory  approval of the merger by the
        Federal  Energy   Regulatory   Commission   (FERC)  and  Public  Utility
        Commission of Texas (Texas Commission).  Under the FERC-approved  merger
        settlement  agreement the  divestiture of 550 MW of generating  capacity
        comprised  of 300 MW of capacity in the  Southwest  Power Pool (SPP) and
        250 MW of capacity in the Electric  Reliability Council of Texas (ERCOT)
        is required.  The FERC is  requiring  AEP and CSW to divest their entire
        ownership  interest in and operational  control of the entire generating
        facilities that produce the capacity to be divested.  The divestiture of
        the  identified  ERCOT  capacity must be completed by March 15, 2001 and
        for the SPP capacity by July 1, 2002. The FERC found that certain energy
        sales in SPP and  ERCOT  would be a  reasonable  and  effective  interim
        mitigation  measure  until  completion  of the  required  SPP and  ERCOT
        divestitures.  The Texas settlement calls for the divestiture of a total
        of 1,604 MW of existing and proposed  generating  capacity  within Texas
        inclusive of 250 MW ordered by FERC.  Divestiture  can not proceed until
        two years  after the merger  closes to satisfy the  requirements  to use
        pooling-of-interests accounting treatment.

               The current annual dividend rate per share of AEP common stock is
        $2.40.  The dividends per share reported on the statements of income for
        prior  periods  represent  pro  forma  amounts  and are  based  on AEP's
        historical annual dividend rate of $2.40 per share. If the dividends per
        share reported for prior periods were based on the sum of the historical
        dividends  declared by AEP and CSW,  the annual  dividend  rate would be
        $2.60 per combined share.

3.      COOK NUCLEAR PLANT SHUTDOWN

               As  discussed  in Note 2 of the Notes to  Consolidated  Financial
        Statements  in the 1999 Annual  Report,  the Cook Nuclear Plant was shut
        down in September  1997 due to questions  regarding the  operability  of
        certain safety systems that arose during a Nuclear Regulatory Commission
        (NRC) architect engineer design inspection. The two-unit, 2,110 megawatt
        plant  is  owned  and  operated  by the  Company-s  subsidiary,  Indiana
        Michigan Power Company (I&M).

               On July 5,  2000,  Cook  Nuclear  Plant  Unit 2, the  first  unit
        scheduled to restart, reached 100% power completing its restart process.

               On July 26, 2000, the Company  announced that the restart of Cook
        Nuclear  Plant  Unit 1 would cost an  additional  $145  million  and was
        scheduled to occur in the first  quarter of 2001.  Unforeseen  issues or
        difficulties   encountered   in  preparing  Unit  1  for  restart  could
        potentially delay its return to service.

               Expenditures  to  restart  the Cook units had been  estimated  to
        total approximately $574 million. The additional $145 million raises the
        total estimate to $719 million.  Through June 30, 2000, $534 million has
        been spent.  For the six months  ended June 30, 2000,  restart  costs of
        $181  million  have been  recorded in other  operation  and  maintenance
        expense,   including  amortization  of  $20  million  of  restart  costs
        previously  deferred in  accordance  with  settlement  agreements in the
        Indiana and Michigan retail  jurisdictions.  At June 30, 2000,  deferred
        restart costs of $140 million are included in regulatory assets.

               The costs of the extended  outage and restart efforts will have a
        material  adverse  effect on future  results of  operations  and on cash
        flows until the second unit is restarted.  The  amortization  of restart
        costs  deferred  under  Indiana  and  Michigan   retail   jurisdictional
        settlement  agreements  will  adversely  affect  results  of  operations
        through December 31, 2003 when the amortization  period ends. The annual
        amortization  of the restart cost  deferrals is $40 million.  Management
        believes  that  Unit 1 of the  Cook  Plant  will  also  be  successfully
        returned  to  service.  However,  if for some  unknown  reason it is not
        returned to service or its return is delayed significantly it would have
        an even greater material adverse effect on future results of operations,
        cash flows and financial condition.

4.      FINANCING AND RELATED ACTIVITIES

               During the first six  months of 2000,  subsidiaries  issued  $751
        million of  long-term  notes at variable  interest  rates with due dates
        ranging from 2001 to 2007. Also short-term debt borrowings  increased by
        $1.1  billion.  The  Company  has in the  past,  and may in the  future,
        acquire  outstanding  debt and preferred stock securities in open market
        transactions.

               Retirements  of debt were:  first  mortgage  bonds  totaling $398
        million  with  interest  rates  ranging from 6.35% to 8.4% and due dates
        ranging from 2000 to 2024, $268 million of long-term notes with variable
        interest  rates as well as fixed rates ranging from 6.43% to 6.57% and a
        $625 million  revolving credit agreement that matured and was refinanced
        with short-term debt.

               During the second quarter the AEP System established a Money Pool
        to coordinate  short-term  borrowings  for certain of its  subsidiaries,
        primarily the U.S. domestic electric utility  operating  companies.  The
        operation  of the Money Pool is  designed  to match on a daily basis the
        available cash and borrowing  requirements of the participants,  thereby
        minimizing the need for borrowings from external sources. The daily cash
        positions of the participants are netted and if there is a deficiency in
        cash, the Company raises funds through external borrowing. If there is a
        net excess in cash,  existing external  borrowings are paid down, or, if
        there  are  no  external  borrowings  maturing,  the  excess  funds  are
        invested.

     CSW  Credit,  Inc.,  a  subsidiary,   factors  electric  customer  accounts
receivable for affiliated  operating companies and unaffiliated  companies.  CSW
Credit,  Inc.  issues  commercial  paper  on a stand  alone  basis  and does not
participate  in the Money Pool. In June 2000 the factoring of customer  accounts
receivable for affiliated  companies was expanded as a result of the merger.  At
June 30, 2000,  CSW Credit,  Inc. had a $2 billion  revolving  credit  agreement
which had $1.2 billion of commercial paper outstanding.

5.      RATE MATTERS

        FERC

            As discussed in Note 3 of the Notes to Financial  Statements  of the
      1999  Annual  Report,  certain  AEP System  companies  filed a  settlement
      agreement for FERC approval related to an open access transmission tariff.
      The  Company  made a provision  in 1999 for an agreed to refund  including
      interest which was part of the settlement agreement.

            On March 16, 2000, the FERC approved the settlement  agreement filed
      in December  1999  resolving  the issues on  rehearing  of a July 30, 1999
      order.  Under terms of the  settlement,  AEP is  required to make  refunds
      retroactive to September 7, 1993 to certain customers affected by the July
      30, 1999 FERC order.  The refunds were made in two  payments.  Pursuant to
      FERC orders the first  payment  was made in  February  2000 and the second
      payment was made on August 1, 2000. In addition, a new lower rate of $1.55
      kw/month was made effective January 1, 2000, for all transmission  service
      customers.  Also as agreed,  a new rate of $1.42  kw/month  took effect on
      June  16,  2000  upon  consummation  of the AEP and CSW  merger.  Prior to
      January 1, 2000, the rate was $2.04  kw/month.  Unless the Company and the
      market  grow the volume of physical  power  transactions  to increase  the
      utilization of the AEP System's  transmission  lines,  the new open access
      transmission  rate will adversely  impact future results of operations and
      cash flows.

        West Virginia

               As  discussed  in Note 3 of the Notes to  Consolidated  Financial
        Statements  of  the  1999  Annual  Report,   the  Company?s   subsidiary
        Appalachian  Power Company (APCo) has been involved in a rate proceeding
        regarding base and expanded net energy cost (ENEC) rates. On February 7,
        2000, APCo and other parties to the proceeding filed a Joint Stipulation
        and Agreement for Settlement (Joint Stipulation) with the Public Service
        Commission of West Virginia (WVPSC) for approval.

               The Joint  Stipulation's  main  provisions  include  no change in
        either base or ENEC rates effective  January 1, 2000 from those base and
        ENEC rates in effect  from  November  1, 1996 until  December  31,  1999
        (these rates  provide for recovery of  regulatory  assets  including any
        generation related regulatory assets through frozen transition rates and
        a wires  charge of 0.5 mills per kwh);  the  suspension  of annual  ENEC
        recovery  proceedings and deferral accounting for over or under recovery
        effective January 1, 2000; the retention,  as a regulatory liability, on
        the books of the net  cumulative  deferred ENEC recovery  balance of $66
        million as  established by a WVPSC order on December 27, 1996. The Joint
        Stipulation provides that when deregulation of generation occurs in West
        Virginia  (WV),  APCo will use this  retained  regulatory  liability  to
        reduce generation-related regulatory assets and, to the extent possible,
        any additional costs or obligations that deregulation may impose.

               Also under the Joint Stipulation  APCo's share of any net savings
        from  the  merger  between  the  Company  and  Central  and  South  West
        Corporation  prior to December  31, 2004 shall be retained by APCo.  All
        costs  incurred in the merger that were allocated to APCo shall be fully
        charged to expense as of December  31, 2004 and shall not be included in
        any WV rate  proceeding  after that date.  After  December 31, 2004, any
        distribution savings related to the merger will be reflected in rates in
        any future rate  proceeding  before the WVPSC to establish  distribution
        rates or to adjust  rate caps  during  the  transition  to market  based
        rates.  When  deregulation of generation  occurs in WV, the net retained
        generation   related  merger  savings  shall  be  used  to  recover  any
        generation  related  regulatory  assets that are not recovered under the
        other  provisions of the Joint  Stipulation and the mechanisms  provided
        for in the  deregulation  legislation  and, to the extent  possible,  to
        recover any additional costs or obligations that deregulation may impose
        on APCo. Regardless of whether the net cumulative deferred ENEC recovery
        balance  and the net  merger  savings  are  sufficient  to offset all of
        APCo's  generation-related  regulatory  assets,  under  the terms of the
        Joint Stipulation there will be no further explicit adjustment to APCo's
        rates to provide for recovery of  generation-related  regulatory  assets
        beyond the above discussed  specific  adjustments  provided in the Joint
        Stipulation   and  the  0.5  mills  per  kwh  wires  charge  in  the  WV
        Restructuring Plan (see Note 6 for discussion of WV Restructuring Plan).
        On June  2,  2000,  the  WVPSC  issued  an  order  approving  the  Joint
        Stipulation.

        CPL Fuel Factor Filings

               In March 2000 the Texas Commission  approved a settlement related
        to CPL's January 2000 fuel factor filing. The settlement provided for an
        increase in fuel factor revenues of $43.3 million annually  beginning in
        March 2000 and a  prospective  surcharge  to provide  $24.7  million for
        previously under recovered fuel cost beginning in April 2000.

               In July 2000 CPL filed, with the Texas Commission, an application
        for  authority to implement an increase in fuel factors  effective  with
        the  September  2000 billing  month.  CPL also  proposed to implement an
        interim  fuel  surcharge  to collect  its  under-recovered  fuel  costs,
        including  accumulated  interest,  over a 12-month  period  beginning in
        October 2000. In early August 2000, a settlement was reached between the
        various parties.  The settlement  allows CPL to increase its fuel factor
        by $173.5  million and  provides  for a surcharge  of $21.3  million for
        previously  under-recovered  fuel costs for the period from  December 1,
        1999 through May 31, 2000 and a surcharge  not to exceed  $65.1  million
        for  projected  under-recoveries  for the period from June 2000  through
        August 2000. A compliance  filing detailing the actual  under-recoveries
        for June 2000 through  August 2000 will be made in September  2000.  The
        settlement requires the approval of the Texas Commission.

6.      INDUSTRY RESTRUCTURING

            Restructuring  legislation has been enacted in five of the Company's
        eleven  retail   jurisdictions  that  results  in  the  transition  from
        cost-based  regulation for generation to customer  choice market pricing
        for  the  supply  of   electricity.   The  enactment  of   restructuring
        legislation  and the  ability to  determine  transition  rates and wires
        charges under restructuring legislation results in the discontinuance of
        the application of Statement of Financial  Accounting  Standards  (SFAS)
        71,  "Accounting for the Effects of Certain Types of Regulation."  Prior
        to restructuring,  the electric utility subsidiaries accounted for their
        operations according to the cost-based  regulatory accounting principles
        of SFAS 71.  Under the  provisions  of SFAS 71,  regulatory  assets  and
        regulatory  liabilities are recorded to reflect the economic  effects of
        regulation  and  to  match  expenses  with   regulated   revenues.   The
        discontinuance  of the  application  of SFAS  71 is  based  on SFAS  101
        "Accounting  for the  Discontinuance  of  Application  of Statement 71".
        Pursuant  to those  requirements  and further  guidance  provided in the
        Financial Accounting Standards Board's Emerging Issues Task Force (EITF)
        Issue 97-4,  a company is required to  write-off  regulatory  assets and
        liabilities related to deregulated  operations,  unless recovery of such
        amounts is provided  through  rates to be  collected in a portion of the
        company's  operations which continues to be regulated.  Additionally,  a
        company  experiencing a discontinuance  of cost-based rate regulation is
        required to determine  if any plant assets are impaired  under SFAS 121,
        "Accounting  for the Impairment of Long-Lived  Assets and for Long-Lived
        Assets to be Disposed  of." A SFAS 121  accounting  impairment  analysis
        involves  estimating future  non-discounted  net cash flows arising from
        the use of an asset. If the  undiscounted  net cash flows exceed the net
        book value of the asset,  then there is no  impairment  of the asset for
        accounting purposes.

             As legislative  and regulatory  proceedings  evolve,  the Company's
        subsidiaries are applying the standards discussed above.  Following is a
        summary of restructuring legislation, the status of the transition plans
        and the status of electric  utility  subsidiaries'  accounting to comply
        with the changes.

        Virginia Restructuring

               Under a 1999 Virginia restructuring law a transition to choice of
        supplier for retail  customers  will  commence on January 1, 2002 and be
        completed,  subject  to a  finding  by the  Virginia  State  Corporation
        Commission (Virginia SCC) that an effective competitive market exists by
        January 1, 2004 but not later than January 1, 2005.

               The  Virginia  restructuring  law  provides  an  opportunity  for
        recovery of just and  reasonable  net  stranded  generation  costs.  The
        mechanisms in the Virginia law for stranded cost recovery are: a capping
        of incumbent utility transition rates until as late as July 1, 2007, and
        the  application  of a wires  charge upon  customers  who may depart the
        incumbent  utility  in favor  of an  alternative  supplier  prior to the
        termination of the rate cap. The law provides for the  establishment  of
        capped  rates  prior to  January  1, 2001 and  establishment  of a wires
        charge  by the  fourth  quarter  of  2001.  Since  APCo,  the  Company's
        subsidiary operating in Virginia,  does not intend to request new rates,
        its current rates will become the capped rates.

        West Virginia Restructuring Plan

               As  discussed  in Note 5 of the Notes to  Consolidated  Financial
        Statements  in the 1999  Annual  Report,  the  WVPSC  issued an order on
        January 28, 2000 approving an electricity  restructuring  plan. On March
        11, 2000, the West Virginia  legislature approved the restructuring plan
        by joint resolution. The joint resolution provides that the WVPSC cannot
        implement the plan until the legislature makes necessary tax law changes
        to preserve the revenues of the state and local governments. The Company
        provides   electric   service  in  West  Virginia  through  APCo  and  a
        distribution only subsidiary, Wheeling Power Company (WPCo).

               The  provisions  of the  restructuring  plan provide for customer
        choice to begin on January 1, 2001,  or at a later date set by the WVPSC
        after  all  necessary   rules  are  in  place  (the  "starting   date");
        deregulation  of  generation  assets  occurring  on the  starting  date;
        functional  separation of the generation,  transmission and distribution
        businesses on the starting date and their legal  corporate or structural
        separation  no later than January 1, 2005; a transition  period of up to
        13 years,  during  which the  incumbent  utility  must  provide  default
        service for customers who do not change  suppliers unless an alternative
        default supplier is selected through a WVPSC-sponsored  bidding process;
        capped and fixed rates for the 13-year  transition  period as  discussed
        below;  deregulation of metering and billing;  a 0.5 mills per kwh wires
        charge applicable to all retail customers for the period January 1, 2001
        through  December  31,  2010  intended  to provide  for  recovery of any
        stranded cost  including net  regulatory  assets;  establishment  by the
        Company of a rate  stabilization  deferral balance of $81 million by the
        end of year ten of the transition period to be used as determined by the
        WVPSC to offset  market  prices paid for  electricity  in the  eleventh,
        twelfth, and thirteenth year of the transition period by residential and
        small commercial customers that do not choose an alternative supplier.

               Default rates for residential and small commercial  customers are
        capped for four  years  after the  starting  date and then  increase  as
        specified in the plan for the next six years.  In years  eleven,  twelve
        and thirteen of the transition period, the power supply rate shall equal
        the market price of comparable  power.  Default rates for industrial and
        large  commercial  customers  are  discounted  by 1% for four and a half
        years,  beginning July 1, 2000, and then increased at pre-defined levels
        for the next three  years.  After seven years the power  supply rate for
        industrial  and large  commercial  customers  will be market based.  The
        Company's Joint Stipulation agreement,  discussed in Note 5 above, which
        was approved by the WVPSC on June 2, 2000 in connection with a base rate
        filing,  also  provides  additional  mechanisms to recover the Company's
        regulatory assets.

        APCo Discontinues Application of SFAS 71

               In June 2000 APCo discontinued the application of SFAS 71 for the
        Virginia  and  West  Virginia  retail  jurisdictional  portions  of  its
        generation  business  since  generation  is no longer  considered  to be
        cost-based regulated in those jurisdictions and it was able to determine
        its transition rates and wires charges.  The  discontinuance in the West
        Virginia  jurisdiction  was  possible  as a  result  of a June  2,  2000
        approval of the Joint Stipulation which established rates, wires charges
        and regulatory asset recovery procedures during the transition period to
        market rates.  APCo was also able to discontinue  application of SFAS 71
        for the generation  portion of its Virginia  retail  jurisdiction  after
        management decided that it would not request capped rates different from
        its current rates. The existence of effective restructuring  legislation
        in Virginia and the probability that the West Virginia legislation would
        become  effective  with the passage of required tax  legislation in 2001
        supported  management's  decision  to  discontinue  SFAS  71  regulatory
        accounting for APCo.

    APCo's discontinuance of SFAS 71 for generation resulted in an extraordinary
     gain of $9 million  because  management  believes  that all net  regulatory
     assets related to the Virginia and West Virginia  generation  business will
     be recovered.  Under the provisions of EITF 97-4, APCo's generation-related
     net regulatory assets were transferred to the transmission and distribution
     portion of the business and will be amortized as they are recovered through
     charges to customers.  APCo performed an accounting  impairment analysis of
     generation  assets under SFAS 121 and concluded  there was no impairment of
     generation assets.

        Ohio Restructuring Law and Transition Plan Filing

               As  discussed  in Note 5 of the Notes to  Consolidated  Financial
        Statements in the 1999 Annual  Report,  the Ohio Electric  Restructuring
        Act of 1999 (the Act) provides for, among other things,  customer choice
        of  electricity  supplier,  a residential  rate  reduction of 5% for the
        generation portion of rates and a freezing of generation rates including
        fuel rates  beginning  on January 1, 2001.  The Act also  provides for a
        five-year  transition  period to move from  cost  based  rates to market
        pricing for  generation  services.  It authorizes  the Public  Utilities
        Commission  of Ohio (PUCO) to address  certain major  transition  issues
        including unbundling of rates and the recovery of transition costs which
        include  regulatory  assets,  generating  asset  impairments  and  other
        stranded  costs,  employee  severance  and  retraining  costs,  consumer
        education  costs and other costs.  Stranded costs are  generation  costs
        that are not deemed to be recoverable in a competitive market.

               On March  28,  2000,  the PUCO  staff  issued  its  report on the
        Company's  transition  plan  filings  for its  subsidiaries,  Ohio Power
        Company  (OPCo) and Columbus  Southern  Power Company  (CSP).  On May 8,
        2000, a stipulation  agreement between the Company,  the PUCO staff, the
        Ohio Consumers'  Counsel and other concerned  parties was filed with the
        PUCO for approval. The key provisions of the stipulation agreement are:

o           Recovery of  generation-related  regulatory  assets over seven years
            for OPCo and eight years for CSP through frozen transition rates for
            the first five years of the  recovery  period and a wires charge for
            the remaining years.

o           A shopping  incentive (a price  credit) of 2.5 mills per kwh for the
            first 25% of CSP residential customers that switch suppliers.  There
            is no shopping incentive for OPCo customers.

o           The  absorption  of $40  million  by CSP and OPCo ($20  million  per
            Company) of consumer  education,  implementation and transition plan
            filing costs with deferral of the remaining  costs,  plus a carrying
            charge,  as a regulatory  asset for recovery in future  distribution
            rates.

o           The  companies  will make  available  a fund of up to $10 million to
            reimburse  customers who chose to purchase  their power from another
            company for certain transmission charges imposed by Pennsylvania-New
            Jersey-Maryland  transmission  organization  (PJM)  and/or a midwest
            independent system operator (Midwest ISO) on generation  originating
            in the Midwest ISO or PJM areas.

o           The statutory 5% reduction in the generation  component of
            residential tariffs will remain in effect for the entire 5 year
            transition  period.

o           The  companies'  request for a $90 million gross receipts tax rider
            to recover duplicate gross receipts tax will be
            litigated separately.

           Hearings on the stipulation and the gross receipts tax issue were
        held in June 2000. Approval of the stipulation agreement by the PUCO and
        a decision on the gross receipt tax issue are pending.

        Potential For Write Offs In The Ohio Jurisdiction

               Management   has   concluded   that  as  of  June  30,  2000  the
        requirements   to  apply  SFAS  71  continue  to  be  met  in  the  Ohio
        jurisdiction.  The Company's accounting for the generation business will
        continue to be in accordance with SFAS 71 in the Ohio  jurisdiction  and
        will continue to be considered to be cost-based regulated for accounting
        purposes  until the amount of  transition  rates and stranded cost wires
        charges are determined and known. OPCo and CSP will therefore, be unable
        to  discontinue  SFAS 71  regulatory  accounting  until the  stipulation
        agreement is approved  and/or the PUCO issues its  restructuring  order.
        The law requires that the PUCO issue such an order no later than October
        2000.

               Upon the discontinuance of SFAS 71 the Company will have to write
        off its Ohio jurisdictional  generation-related regulatory assets to the
        extent that they cannot be recovered under the frozen  transition  rates
        and  stranded  costs  distribution  wires  charges  and record any asset
        accounting impairments. An impairment loss would be recorded, under SFAS
        No.  121,  to the extent that the cost of  generation  assets  cannot be
        recovered through non-discounted  generation-related revenues during the
        transition period and future market prices.

               The amount of regulatory assets recorded on the books at June 30,
        2000 applicable to the Ohio retail jurisdictional generating business is
        $757 million before related tax effects.  Due to the planned  closing of
        the Company's  affiliated  mines,  including  the Meigs mine,  projected
        generation-related  regulatory  assets as of December 31, 2000 (the date
        that recoverable generation-related regulatory assets are measured under
        the Ohio law) allocable to the Ohio retail jurisdiction are estimated to
        exceed  $800  million,  before  income tax  effects.  Recovery  of these
        regulatory  assets  is  being  sought  as a part of the  Company's  Ohio
        transition plan filings and is provided for by the stipulation agreement
        presently  before the PUCO for approval.  Based on transition  rates and
        wires charges  currently in the stipulation  agreement and  management's
        current  projections  of  future  market  prices,  management  does  not
        anticipate  that the Company will  experience  material  tangible  asset
        accounting  impairment  or  regulatory  asset  write-offs.  Whether  the
        Company will experience material regulatory asset write-offs will depend
        on whether the PUCO approves the Company's  stipulation  agreement which
        provides for their recovery.

               A determination  of whether the Company will experience any asset
        impairment  loss  regarding  its Ohio retail  jurisdictional  generating
        assets  and  any  loss  from  a  possible   inability  to  recover  Ohio
        generation-related  regulatory  assets and other transition costs cannot
        be made until such time as the  transition  rates and the wires  charges
        are determined through the regulatory  process. In the event the Company
        is  unable  to  recover  all  or a  portion  of  its  generation-related
        regulatory  assets,  stranded costs and other transition costs including
        the duplicate gross receipt tax, it could have a material adverse effect
        on results of operations, cash flows and possibly financial condition.

     Texas and Arkansas Restructuring

            In June 1999 restructuring  legislation was signed into law in Texas
        that will restructure the electric utility industry (Texas Legislation).
        The Texas Legislation, among other things:

o           gives Texas customers of  investor-owned  utilities the opportunity
            to choose their electric  provider  beginning  January 1,
             2002;
o            provides  for  the  recovery  of  regulatory  assets  and of  other
             stranded  costs through  securitization  and  non-bypassable  wires
             charges;

o           requires reductions in nitrogen oxide and sulfur dioxide emissions;
o            provides a rate freeze until  January 1, 2002 followed by a 6% rate
             reduction  for  residential  and  small  commercial  customers,  an
             additional rate reduction for low-income  customers and a number of
             customer protections;

o sets an earnings test for the three years of rate freeze (1999 through  2001);
o sets  certain  limits for  ownership  and  control of  generation  capacity by
companies; and

o            requires a filing after January 10, 2004 to finalize stranded costs
             (2004 true-up  proceeding)  including final fuel recovery balances,
             regulatory assets, certain environmental costs,  accumulated excess
             earnings and other issues.


<PAGE>


             Delivery of electricity will continue to be the  responsibility  of
        the local electric  transmission  and  distribution  utility  company at
        regulated  prices.  Each electric utility must submit a plan to unbundle
        its  business  activities  into a  retail  electric  provider,  a  power
        generation company and a transmission and distribution utility.

             In 1999  legislation  was enacted in Arkansas that will  ultimately
        restructure the electric utility industry (Arkansas Legislation).  Major
        points of the Arkansas Legislation are:

o        Retail  competition  begins  January 1, 2002 but can be delayed until
         as late as June 30, 2003 by the Arkansas  Public Service
         Commission (Arkansas Commission).
o Transmission facilities must be operated by an ISO if owned by a company which
also owns  generation  assets.  o Rates will be frozen for one to three years.
o        Market power issues will be addressed by the Arkansas Commission.

             SWEPCo  filed a business  unbundling  plan in  Arkansas on June 30,
2000.

             CPL,  SWEPCo and WTU filed their business  separation  (unbundling)
        plans  with the Texas  Commission  on  January  10,  2000.  The  filings
        described a financial and  accounting  functional  separation  but not a
        legal  or  structural  separation,  described  how  operations  will  be
        physically  separated  and the functions  they will  perform,  described
        competitive  energy services,  and provided a code of conduct.  In March
        2000, the Texas Commission ruled that the  subsidiaries'  plans were not
        in compliance  with the Texas  Legislation  and ordered revised plans be
        submitted to separate the generation business from the wires business in
        separate  legal  entities  by  January  1,  2002.  In May 2000 a revised
        separation plan was filed,  which the Texas Commission  approved on July
        7, 2000 in an interim order.

                  Under the Texas  Legislation,  electric utilities are allowed,
        with the approval of the Texas  Commission,  to recover  stranded  costs
        including   generation-related   regulatory   assets  that  may  not  be
        recoverable in a future  competitive  market.  The approved costs can be
        refinanced  through  securitization,  which  is  a  financing  structure
        designed  to provide  state  sponsored  lower  financing  costs than are
        available   through   conventional   public  utility   financings.   The
        securitized   amounts  plus  interest  are  then  recovered   through  a
        non-bypassable  wires charge.  In 1999 CPL filed an application with the
        Texas Commission to securitize approximately $1.27 billion of its retail
        generation-related  regulatory  assets and  approximately $47 million in
        other qualified restructuring costs.

                  On  February  10,  2000,  the  Texas  Commission   tentatively
        approved a settlement, which will permit CPL to securitize approximately
        $764 million of net  regulatory  assets.  The Texas  Commission's  order
        authorized  issuance  of up to  $797  million  of  securitization  bonds
        including the $764 million for recovery of net regulatory assets and $33
        million for other  qualified  refinancing  costs.  The $764  million for
        recovery of net regulatory  assets reflects the recovery of $949 million
        of  regulatory  assets  offset  by $185  million  of  customer  benefits
        associated with  accumulated  deferred income taxes.  CPL had previously
        proposed in its filing to flow these benefits back to customers over the
        14-year  term of the  securitization  bonds.  The  remaining  regulatory
        assets originally  requested by CPL in its 1999  securitization  request
        has been  included  in a March 2000  filing  with the Texas  Commission,
        requesting recovery of an additional $1.1 billion of stranded costs. The
        March 2000 filing for $1.1 billion  includes  recovery of  approximately
        $800 million of South Texas Project  (STP) nuclear plant costs  included
        in utility  plant on the  Balance  Sheet and  previously  identified  as
        "Excess Cost Over Market" (ECOM) by the Texas  Commission for regulatory
        purposes.  A final  determination  on recovery will occur as part of the
        2004  true-up  proceeding  and  the  total  amount  recoverable  can  be
        securitized.

                  On  April  11,   2000,   four   parties   appealed  the  Texas
        Commission's  securitization  order to the Travis County District Court.
        One of these appeals  challenges  the ability to recover  securitization
        charges under the Texas Constitution.  CPL will not be able to issue the
        securitization bonds until these appeals are resolved.  As a result, the
        securitization bonds are not likely to be issued until 2001.

            The financial  statements of CPL,  SWEPCo and WTU have  historically
        reflected  the effects of  applying  the  requirements  of SFAS 71. As a
        result  of  the  scheduled  deregulation  of  generation  in  Texas  and
        Arkansas,  the application of SFAS 71 for the generation  portion of the
        business in those states was  discontinued in 1999. Under the provisions
        of EITF  97-4,  CPL's  generation-related  net  regulatory  assets  were
        transferred to the transmission and distribution portion of the business
        and  will  be  amortized  as  they  are  recovered  through  charges  to
        customers.   Management   believes  that   substantially  all  of  CPL's
        generation-related  regulatory assets should be recovered as provided by
        the Texas  Legislation  when an electric utility has a stranded cost. If
        future events were to occur that made the recovery of regulatory  assets
        no longer  probable,  CPL would  write-off  the  portion of such  assets
        deemed unrecoverable as a non-cash charge to earnings.

             CPL's recovery of generation-related regulatory assets and stranded
        costs are subject to a final  determination  by the Texas  Commission in
        2004. The Texas  Legislation  provides that all such finally  determined
        stranded costs will be recovered.  Since SWEPCo and WTU are not expected
        to have net stranded costs, all  generation-related  non-recoverable net
        regulatory  assets  were  written  off in 1999  when  they  discontinued
        application of SFAS 71 regulatory accounting. An impairment analysis for
        generation  assets under SFAS 121 was completed for CPL,  SWEPCo and WTU
        which concluded there was no accounting  impairment of generation assets
        when the application of SFAS 71 was discontinued. An impairment analysis
        involves  estimating  future net cash flows  arising  from the use of an
        asset. If the  undiscounted  net cash flows exceed the net book value of
        the  asset,  then  there is no  impairment  of the asset to  record  for
        accounting  purposes.  CPL,  SWEPCo and WTU will test their generation
        assets for impairment  under  SFAS  121  when  circumstances  change.
        However,  on  a discounted basis the cash flows are less than CPL's
        generating  asset's net book  value and  together  with its
        generation-related  regulatory  assets create a recoverable stranded
        cost under the Texas Legislation.
                  The Texas  Legislation also provides that each year during the
        1999 through 2001 rate freeze period,  electric utilities are subject to
        an earnings test. For electric  utilities with stranded  costs,  such as
        CPL,  any  earnings  in excess  of the most  recently  approved  cost of
        capital in its last rate case must be applied to reduce  stranded costs.
        Utilities  without  stranded costs,  such as SWEPCo and WTU, must either
        flow such  amounts back to  customers  or make  capital  expenditure  to
        improve  transmission  or  distribution  facilities  or to  improve  air
        quality.

                  A Texas  settlement  agreement in connection  with the AEP and
        CSW  merger  permits  CPL to apply  for  regulatory  purposes  up to $20
        million  of STP ECOM  Plant  assets  a year in 2000  and 2001 to  reduce
        excess  earnings,  if any. For book purposes, plant assets will be
        depreciated on a systematic and rational basis unless impaired. To the
        extent  excess  earnings  exceed $20 million in 2000 or 2001 CPL will
        establish a regulatory  liability by a charge to earnings.

                 Beginning  January 1,  2002,  fuel costs will not be subject to
        Texas Commission fuel  reconciliation  proceedings.  Consequently,  CPL,
        SWEPCo  and WTU will  file a final  fuel  reconciliation  with the Texas
        Commission  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 Company continues to analyze the impact of the electric utility
        industry  restructuring   legislation  on  the  Texas  electric  utility
        companies.  Although  management  believes  that the  Texas  Legislation
        provides for full recovery of the Company's  stranded costs and that the
        Company  does  not  have a  recordable  accounting  impairment  a  final
        determination of whether the Company will experience any accounting loss
        from an inability to recover  generation-related  regulatory  assets and
        other  restructuring  related costs in Texas and Arkansas cannot be made
        until  such  time as the  litigation  and  the  regulatory  process  are
        complete following the 2004 true-up proceeding. In the event the Company
        is unable after the 2004 true-up  proceeding to recover all or a portion
        of its  generation-related  regulatory assets,  stranded costs and other
        restructuring  related costs, it could have a material adverse effect on
        results of operations, cash flows and possibly financial condition.

7.      BUSINESS SEGMENTS

               The Company's  principal  business segment is its cost-based rate
        regulated  Domestic  Electric  Utility  business  consisting  of  eleven
        regulated utility operating companies providing residential, commercial,
        industrial  and  wholesale  electric  services  in eleven  states.  Also
        included in this  segment are the  Company's  electric  power  wholesale
        marketing and trading activities within two transmission  systems of the
        AEP  System  that are  conducted  as part of  regulated  operations  and
        subject to cost of service rate regulation.

               The Domestic  Electric Utility business  includes both the retail
        and wholesale domestic electricity supply businesses which are regulated
        in Kentucky,  Indiana, Michigan,  Louisiana,  Oklahoma and Tennessee and
        are in the process of transitioning to market based pricing in Arkansas,
        Ohio,  Texas,  West Virginia and Virginia.  Since the domestic  electric
        utility  companies have not yet structurally  separated their retail and
        wholesale electricity supply business from their regulated  distribution
        service business separate financial data is not available.  The Domestic
        Electric Utility business is reported as one business segment.

               The  income  statement   captions   Worldwide  Electric  and  Gas
        Operations include two segments: Worldwide Energy Investments and other.
        The  Worldwide  Energy  Investments   segment  represents  domestic  and
        international  investments in  energy-related  gas and electric projects
        and operations.  It also includes the development and management of such
        projects and operations.  Such investment  activities  include  electric
        generation,  supply and distribution,  and natural gas pipeline, storage
        and other natural gas services.

               The other  segment  which is  included  in the  income  statement
        captions  Worldwide  Electric  and Gas includes  non-regulated  electric
        trading   activities   outside  of  AEP's  marketing  area  (beyond  two
        transmission  system's  from AEP's  system) and gas trading  activities,
        telecommunication  services, and the marketing of various energy related
        products and services.  Financial data for the three  business  segments
        for the six  months  ending  June  30,  2000  and  1999 is  shown in the
        following table:


<PAGE>
<TABLE>
<CAPTION>



                                 Domestic    Worldwide
                                 Regulated   Electric and

                                 Electric    Gas                      Reconciling    AEP
                                 Utilities*  Operations     Other     Adjustments    Consolidated
                                 ---------   ------------   -----     -----------    ------------
                                                         (in millions)
 June 30, 2000
<S>                              <C>           <C>          <C>            <C>          <C>
        Revenues from
          external customers     $ 4,892       $1,273       $   48         $  -         $ 6,213
        Revenues from
          transactions with other

          operating segments        -             147           67          (214)          -
        Segment net income (loss)    110           31          (10)          -              131
        Total assets              29,308        7,204        3,887           -           40,399
 June 30, 1999
        Revenues from

          external customers       4,640        1,230           11           -            5,881
        Revenues from
          transactions with other

          operating segments        -              28           78          (106)          -
        Segment net income (loss)    342           45           (3)          -              384
        Total assets              27,100        7,173        1,446           -           35,719

        *  Includes  the  domestic   generation   retail  and  wholesale  supply
        businesses  a  significant  portion of which is  undergoing a transition
        from  regulated cost based rates to open access market pricing but which
        have  not yet  been  unbundled  i.e.,  structurally  separated  from the
        Company's vertically integrated electric utility business.
</TABLE>
8.      SOUTH AMERICAN INVESTMENTS

                At June 30, 2000, CSW International  owned a 44% equity interest
        in Vale, a Brazilian  electric  operating company which it had purchased
        for a total of $149 million.  The investment is covered by a put option,
        which,  if  exercised,  requires  Vale to purchase  CSW  International's
        shares at a minimum  price equal to the U.S.  dollar  equivalent  of CSW
        International's  purchase price.  As a result,  management has concluded
        that CSW International's  investment carrying amount will not be reduced
        below  the put  option  value  unless  it is  deemed  to be a  permanent
        impairment  and Vale is deemed  unable to fulfill  its  responsibilities
        under  the  put  option.  Vale  has  experienced  cumulative  losses  of
        approximately  $22 million,  net of tax,  related to operations  and the
        devaluation  of  the  Brazilian   Real.   Pursuant  to  the  put  option
        arrangement, these losses are not reflected in the carrying value of the
        Vale investment.  Conversely,  CSW International  will not recognize any
        future earnings from Vale until the losses are recovered.

                As of June 30, 2000, CSW International had invested $110 million
        in stock of a Chilean electric company.  The investment is classified as
        securities  available  for sale and as such changes in market value that
        are  deemed to be  temporary  and  foreign  exchange  rate  changes  are
        reflected in other  comprehensive  income. In the second quarter of 2000
        management determined that the decline in market value of the shares was
        other than temporary.  As a result a write down to market of $33 million
        ($21  million  after tax) was  recorded  in June 2000 and is included in
        worldwide  electric and gas  expenses.  Based on the quarter end foreign
        exchange  rate,  the value of the  investment  at June 30,  2000 was $59
        million.  The  decline  in  foreign  exchange  rates has  resulted  in a
        cumulative  loss of $18 million ($11  million  after tax) as of June 30,
        2000 which is included in Other Comprehensive Income.

9.      CONTINGENCIES

        COLI Litigation

               As  discussed  in Note 6 of the Notes to  Consolidated  Financial
        Statements  in the 1999  Annual  Report,  the  deductibility  of certain
        interest  deductions  related to AEP?s  corporate  owned life  insurance
        (COLI)  program for taxable  years 1991  through 1996 is under review by
        the Internal  Revenue  Service (IRS).  Adjustments  have been or will be
        proposed by the IRS disallowing COLI interest deductions. A disallowance
        of the COLI  interest  deductions  through  June 30,  2000 would  reduce
        earnings by approximately $318 million (including interest).

               The Company made payments of taxes and interest  attributable  to
        COLI  interest  deductions  for taxable years 1991 through 1998 to avoid
        the potential  assessment by the IRS of any additional above market rate
        interest on the contested  amount.  The payments to the IRS are included
        on the consolidated balance sheet in other assets pending the resolution
        of this matter.  The Company is seeking refund through litigation of all
        amounts paid plus interest.

               In order to resolve  this issue,  the Company  filed suit against
        the United States in the U.S.  District Court for the Southern  District
        of  Ohio  in  1998.  In  1999 a U.S.  Tax  Court  judge  decided  in the
        Winn-Dixie Stores v. Commissioner case that a corporate  taxpayer's COLI
        interest deduction should be disallowed. Notwithstanding the Tax Court?s
        decision  in  Winn-Dixie,  management  has  made  no  provision  for any
        possible  adverse  earnings impact from this matter because it believes,
        and has been  advised  by  outside  counsel,  that it has a  meritorious
        position  and will  vigorously  pursue  its  lawsuit.  In the  event the
        resolution  of this  matter  is  unfavorable,  it will  have a  material
        adverse  impact on  results  of  operations,  cash  flows  and  possibly
        financial condition.

        Shareholders' Litigation

               On June 23,  2000,  a  complaint  was filed in the U.S.  District
        Court  for  the  Eastern  District  of  New  York  seeking   unspecified
        compensatory  damages  against  the  Company  and four former or present
        officers.  The  individual  plaintiff  also seeks  certification  as the
        representative  of a class  consisting  of all persons and  entities who
        purchased or otherwise  acquired AEP common stock between July 25, 1997,
        and June 25, 1999. The complaint  alleges that the defendants  knowingly
        violated federal  securities laws by disseminating  materially false and
        misleading  statements  concerning,  among other things, the undisclosed
        materially  impaired  condition of the Cook Nuclear Plant, the Company's
        inability to properly monitor,  manage, repair,  supervise and report on
        operations at the Cook Plant and the materially adverse conditions these
        problems  were  having,  and would  continue to have,  on the  Company's
        deteriorating  financial  condition,  and  ultimately  on the  Company's
        operations,  liquidity and stock price. Three other similar class action
        complaints  have been  filed and it is  anticipated  that the court will
        consolidate   the  various   complaints.   Management   believes   these
        shareholder  actions  are  without  merit and  intends  to  oppose  them
        vigorously.

        CPL Municipal Franchise Fee Litigation

               CPL has been involved in litigation regarding municipal franchise
        fees in Texas as a result of a class  action  suit  filed by the City of
        San  Juan,  Texas in 1996.  The City of San Juan  claims  CPL  underpaid
        municipal  franchise  fees and seeks  damage of up to $300  million plus
        attorney's  fees. CPL filed a counterclaim  for overpayment of franchise
        fees.

               During  1997,  1998 and 1999 the  litigation  moved  procedurally
        through  the  Texas  Court  System  and was  sent to  mediation  without
        resolution.

               In 1999 a class notice was mailed to each of the cities served by
        CPL. Over 90 of the 128 cities  served  declined to  participate  in the
        lawsuit.  However,  CPL has  pledged  that if any final,  non-appealable
        court  decision in the litigation  awards a judgement  against CPL for a
        franchise underpayment, CPL will extend the principles of that decision,
        with regard to the franchise underpayment, to the cities that decline to
        participate  in the  litigation.  In December 1999, the court ruled that
        the class of plaintiffs  would  consist of  approximately  30 cities.  A
        trial date for June 2001 has been set.

               Although CPL  believes  that it has  substantial  defenses to the
        cities'  claims and intends to defend itself  against the cities' claims
        and pursue its counterclaims  vigorously,  management cannot predict the
        outcome of this  litigation  or its impact on the  Company's  results of
        operations, cash flows or financial condition.

        Federal EPA Complaint and Notice of Violation

               As  discussed  in Note 6 of the Notes to  Consolidated  Financial
        Statements in the 1999 Annual  Report,  the Company has been involved in
        litigation  regarding  generating plant emissions.  Notices of Violation
        were  issued  and a  complaint  was  filed  by  the  U.S.  Environmental
        Protection  Agency (Federal EPA) in the U.S. District Court that alleges
        the Company and eleven  unaffiliated  utilities  made  modifications  to
        generating units at certain of their coal-fired  generating  plants over
        the  course of the past 25 years that  extend  unit  operating  lives or
        increase unit generating  capacity without a  preconstruction  permit in
        violation of the Clean Air Act. The  complaint was amended in March 2000
        to add allegations for certain  generating units previously named in the
        complaint  and  to  include   additional  AEP  System  generating  units
        previously  named only in the  Notices of  Violation  in the  complaint.
        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.

               A number of northeastern and eastern states were granted leave to
        intervene  in the Federal  EPA's  action  against the Company  under the
        Clean Air Act.  A lawsuit  against  power  plants  owned by the  Company
        alleging  similar  violations  to those in the Federal EPA complaint and
        Notices of Violation  was filed by a number of special  interest  groups
        and has been consolidated with the Federal EPA action.

               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). Civil penalties,  if ultimately imposed by the court,
        and the cost of any required new  pollution  control  equipment,  if the
        court accepts Federal EPA's contentions, could be substantial.

               On May 10,  2000,  the  Company  filed  motions to dismiss all or
        portions of the  complaints.  Briefing on these motions was completed on
        August  2,  2000.  Management  believes  its  maintenance,   repair  and
        replacement  activities  were in  conformity  with the Clean Air Act and
        intends to vigorously pursue its defense of this matter.

               In the  event the  Company  does 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 where
        states  are  deregulating   generation,   unbundled   transition  period
        generation  rates,  stranded cost wires charges and future market prices
        for electricity.

        NOx Reductions

               As  discussed  in Note 7 of the Notes to  Consolidated  Financial
        Statements  in the 1999  Annual  Report,  Federal EPA had issued a final
        rule (the NOx rule) that  requires  substantial  reductions  in nitrogen
        oxide (NOx) emissions in 22 eastern states,  including certain states in
        which  the AEP  System?s  generating  plants  are  located.  A number of
        utilities,  including certain AEP System companies,  had filed petitions
        seeking a review of the final rule in the U.S.  Court of Appeals for the
        District of Columbia Circuit  (Appeals Court).  In May 1999, the Appeals
        Court  indefinitely  stayed the requirement  that states develop revised
        air quality programs to impose the NOx reductions but did not,  however,
        stay the final compliance date of May 1, 2003. In March 2000 the Appeals
        Court issued a decision  generally  upholding the NOx rule. On April 20,
        2000,  certain  AEP System  companies  and other  petitioners  filed for
        rehearing of this decision  including a rehearing by the entire  Appeals
        Court.  On June 22,  2000,  the Appeals  Court  denied the  petition for
        rehearing  and lifted the stay  related to the  states'  development  of
        revised air quality programs to impose the NOx reductions.  The petition
        for a rehearing before the entire Appeals Court was also denied. The AEP
        System  companies  subject  to the NOx rule  plan to  appeal to the U.S.
        Supreme Court.

               In a  related  matter,  on April  19,  2000,  the  Texas  Natural
        Resource   Conservation   Commission  (TNRCC)  adopted  rules  requiring
        significant reductions in NOx emissions from utility sources,  including
        SWEPCo and CPL. The rule's  compliance date is May 2003 for CPL and 2005
        for  SWEPCo.  The  rule  is  being  challenged  in  state  court  by  an
        unaffiliated utility.

               Preliminary  estimates indicate that compliance with the NOx rule
        upheld by the Appeals  Court as well as  compliance  with the TNRCC rule
        could result in required  capital  expenditures  of  approximately  $1.8
        billion for the Company. Since compliance costs cannot be estimated with
        certainty,  the actual cost to comply could be  significantly  different
        than the Company's  preliminary  estimate  depending upon the compliance
        alternatives selected to achieve reductions in NOx emissions. Unless the
        depreciation  of  such  costs  are  recovered  from  customers   through
        regulated  rates  and/or  future  market  prices for  electricity  where
        generation is  deregulated,  they will have an adverse  effect on future
        results of operations, cash flows and possibly financial condition.

        Other

               The Company  continues  to be involved in certain  other  matters
discussed in the 1999 Annual Report.


<PAGE>





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

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
                     ---------------------------------------

RESULTS OF OPERATIONS

        Net income  declined by $199 million or 105% for the quarter and by $253
million or 66% for the year-to-date period due predominately to the expensing of
costs  related to AEP's  recently  completed  merger with Central and South West
Corporation (CSW), a write down to market of a CSW investment in a company based
in Chile and an  increase in the costs  charged to  operations  and  maintenance
expense to restart the Company's shutdown Cook Nuclear Plant.

        Income statement line items which changed significantly were:

                                         Increase (Decrease)

                                 Second Quarter  Year-To-Date

                                 (in millions) % (in millions) %

Revenues:
  Domestic Regulated Electric

   Utilities. . . . . . . . . . .    $189      8     $252      5
  Worldwide Electric and
   Gas Operations . . . . . . . .      17      3       80      6
Fuel and Purchased Power Expense.     154     19      235     15
Maintenance and Other Operation
   Expense. . . . . . . . . . . .      44      7      125     10
Merger Costs. . . . . . . . . . .     161    N.M.     161    N.M.
Worldwide Electric and Gas
 Operations Expense . . . . . . .      85     17      125     11
Interest and Preferred Dividends.      23      9       33      7
Income Taxes. . . . . . . . . . .     (69)   (57)    (108)   (46)

N.M. = Not Meaningful

        Domestic revenues increased  primarily due to increased  wholesale sales
to  neighboring  utilities and marketers in the eastern  markets of the domestic
regulated  electric utility  business.  The increase in wholesale sales resulted
from growth in energy  trading  operations  and the  availability  of additional
generation in the second quarter.

        Revenues from worldwide electric and gas operations  increased primarily
due to increased  natural gas and gas liquid product prices.  Volumes of natural
gas remained  consistent  with the prior year,  however,  prices have  increased
approximately  50%  rebounding  from a depressed gas market in the first half of
1999.

        The  increase  in  fuel  and  purchased   power  expense  was  primarily
attributable  to a  significant  increase  in the cost of  natural  gas used for
generation and an increase in net generation.

        Maintenance and other operation expense increased largely as a result of
increased  expenditures  to prepare  the Cook Plant  nuclear  units for  restart
following an extended Nuclear Regulatory  Commission (NRC) monitored outage. The
increase  results  from the  effect of  deferring  restart  costs in 1999 and an
increase  in the  restart  expenditure  level.  The Cook Plant began an extended
outage in  September  1997 when both  nuclear  generating  units  were shut down
because of questions  regarding the  operability of certain safety  systems.  In
1999  incremental  restart expenses were deferred in accordance with Indiana and
Michigan  regulatory   commission   settlement  agreements  which  resolved  all
rate-related issues related to the Cook Plant's extended outage. Unit 2 returned
to service in June and achieved full power operation on July 5, 2000. Management
expects,  barring any  unforeseen  events,  that Unit 1 will be restarted in the
first quarter of 2001.

        With  the  consummation  of the  merger  with  CSW,  merger  costs  were
expensed.  The merger costs expensed  included  transaction and transition costs
not allocable to and recoverable  from ratepayers  under  regulatory  commission
approved  settlement  agreements to share net merger savings.  Change in control
payments were also charged to expense.

        Worldwide  electric and gas operations  expenses rose in the quarter due
mainly to a  significant  increase in prices for natural gas used to produce gas
liquid  products  and a write  down to  market  value  of an  available-for-sale
investment in a  Chilean-based  electric  company.  The write down to market was
recognized  in June 2000 since the decline in market value was  determined to be
other than temporary.

        Interest  charges  increased  due to an increase in average  outstanding
short-term  debt  balances and an increase in average  short-term  debt interest
rates reflecting the Company's increased  short-term cash demands and short-term
debt market conditions.

        The  decrease  in income  taxes is  predominately  due to a decrease  in
pre-tax income.

FINANCIAL CONDITION

        Total plant and  property  additions  including  capital  leases for the
year-to-date period were $858 million.

        During the first six months of 2000 the  Company's  subsidiaries  issued
$751 million  principal  amount of long-term  obligations  at variable  interest
rates and retired $1.3 billion  principal amount of long-term debt with interest
rates ranging from 6.35% to 8.40% and increased  short-term debt by $1.1 billion
from  year-end  balances.  The Company  has in the past,  and may in the future,
acquire   outstanding  debt  and  preferred  stock  securities  in  open  market
transactions.  During the second quarter the Company established a Money Pool to
coordinate short-term borrowings for certain of its subsidiaries,  primarily the
U.S. domestic electric utility operating  companies.  The operation of the Money
Pool is  designed  to match on a daily basis the  available  cash and  borrowing
requirements  of the  participants,  thereby  minimizing the need for borrowings
from external  sources.  The daily cash positions of the participants are netted
and if there is a  deficiency  in cash,  the Company  raises  funds  through its
external  borrowing.  If there is a net excess in cash,  external borrowings are
paid down, or, if there are no external  borrowings  maturing,  the excess funds
are invested.

OTHER MATTERS

Cook Nuclear Plant Shutdown

        As  discussed  in  Management's  Discussion  and  Analysis of Results of
Operations and Financial  Condition  (MDA) in the 1999 Annual  Report,  the Cook
Nuclear  Plant was shut down in September  1997 due to questions  regarding  the
operability of certain safety systems that arose during a NRC architect engineer
design inspection.  The two-unit,  2,110 megawatt plant is owned and operated by
the Company's subsidiary, Indiana Michigan Power Company (I&M).

        On July 5, 2000,  Cook Nuclear Plant Unit 2, the first unit scheduled to
restart, reached 100% power completing its restart process.

        On July 26, 2000, the Company announced that the restart of Cook Nuclear
Plant Unit 1 would cost an additional $145 million and was scheduled to occur in
the first quarter of 2001. Any issues or  difficulties  encountered in preparing
Unit 1 for restart could delay its return to service.

        Expenditures  to  restart  the Cook  units had been  estimated  to total
approximately  $574  million.  The  additional  $145  million  raises  the total
estimate to $719  million.  Through June 30, 2000,  $534 million has been spent.
For the six months ended June 30, 2000,  restart costs of $181 million have been
recorded in other operation and maintenance expense,  including  amortization of
$20 million of restart costs  previously  deferred in accordance with settlement
agreements in the Indiana and Michigan retail  jurisdictions.  At June 30, 2000,
deferred restart costs of $140 million are included in regulatory assets.

        The  costs of the  extended  outage  and  restart  efforts  will  have a
material  adverse effect on future results of operations and on cash flows until
the second unit is restarted.  The  amortization of restart costs deferred under
Indiana and Michigan retail  jurisdiction  settlement  agreements will adversely
affect results of operations through 2003 when the amortization period ends. The
annual  amortization  of the restart cost  deferrals is $40 million.  Management
believes  that Unit 1 of the Cook Plant will also be  successfully  returned  to
service.  However,  if for some unknown  reason it is not returned to service or
its  return is delayed  significantly  it would  have an even  greater  material
adverse  effect  on future  results  of  operations,  cash  flows and  financial
condition.

Restructuring Legislation

        Restructuring  legislation has been enacted in five retail jurisdictions
that results in the  transition  from  cost-based  regulation  for generation to
customer choice market pricing for the supply of  electricity.  The enactment of
restructuring  legislation  and the ability to  determine  transition  rates and
wires charges under  restructuring  legislation results in the discontinuance of
the  application  of  Statement  of Financial  Accounting  Standards  (SFAS) 71,
"Accounting  for  the  Effects  of  Certain  Types  of  Regulation."   Prior  to
restructuring,  the electric utility subsidiaries accounted for their operations
according to the cost-based  regulatory  accounting principles of SFAS 71. Under
the  provisions of SFAS 71,  regulatory  assets and regulatory  liabilities  are
recorded to reflect the economic  effects of  regulation  and to match  expenses
with regulated  revenues.  The  discontinuance  of the application of SFAS 71 is
based on SFAS 101 "Accounting for the Discontinuance of Application of Statement
71".  Pursuant  to those  requirements  and  further  guidance  provided  in the
Financial  Accounting  Standards Board's Emerging Issues Task Force (EITF) Issue
97-4,  a company is  required to  write-off  regulatory  assets and  liabilities
related to deregulated  operations,  unless recovery of such amounts is provided
through  rates to be collected in a portion of the  company's  operations  which
continues to be regulated. Additionally, a company experiencing a discontinuance
of cost-based  rate  regulation is required to determine if any plant assets are
impaired under SFAS 121, "Accounting for the Impairment of Long-Lived Assets and
for  Long-Lived  Assets to be  Disposed  of." A SFAS 121  accounting  impairment
analysis  involves  estimating  future net cash flows arising from the use of an
asset.  If the  undiscounted  net cash  flows  exceed  the net book value of the
asset, then there is no impairment of the asset for accounting purposes.

    As legislative and regulatory proceedings evolve, the Company's subsidiaries
are  applying  the  standards  discussed  above.   Following  is  a  summary  of
restructuring  legislation,  the  status  of the  transition  and the  status of
electric utility subsidiaries accounting to comply with the changes.

Virginia Restructuring

        Under a 1999  Virginia  restructuring  law a  transition  to  choice  of
supplier for retail customers will commence on January 1, 2002 and be completed,
subject to a finding by the Virginia State Corporation Commission (Virginia SCC)
that an  effective  competitive  market  exists by January 1, 2004 but not later
than January 1, 2005.

        The Virginia  restructuring  law provides an opportunity for recovery of
just and  reasonable  net  stranded  generation  costs.  The  mechanisms  in the
Virginia  law for stranded  cost  recovery  are: a capping of incumbent  utility
transition  rates until as late as July 1, 2007, and the  application of a wires
charge  upon  customers  who may  depart  the  incumbent  utility in favor of an
alternative  supplier prior to the termination of the rate cap. The law provides
for the establishment of capped rates prior to January 1, 2001 and establishment
of a wires  charge by the fourth  quarter of 2001.  Since  APCo,  the  Company's
subsidiary  operating  in  Virginia,  does not intend to request new rates,  its
current rates will become the capped rates.

West Virginia Restructuring Plan

        As discussed in Note 5 of the Notes to Consolidated Financial Statements
in the 1999  Annual  Report,  the WVPSC  issued  an order on  January  28,  2000
approving  an  electricity  restructuring  plan.  On March  11,  2000,  the West
Virginia  legislature  approved the restructuring plan by joint resolution.  The
joint  resolution  provides  that the WVPSC cannot  implement the plan until the
legislature  makes  necessary  tax law changes to preserve  the  revenues of the
state and local  governments.  The  Company  provides  electric  service in West
Virginia through APCo and a distribution only subsidiary, Wheeling Power Company
(WPCo).

        The provisions of the restructuring  plan provide for customer choice to
begin on  January  1,  2001,  or at a later  date  set by the  WVPSC  after  all
necessary rules are in place (the "starting  date");  deregulation of generation
assets occurring on the starting date;  functional separation of the generation,
transmission  and  distribution  businesses on the starting date and their legal
corporate or  structural  separation no later than January 1, 2005; a transition
period of up to 13  years,  during  which the  incumbent  utility  must  provide
default service for customers who do not change  suppliers unless an alternative
default supplier is selected through a WVPSC-sponsored  bidding process;  capped
and  fixed  rates  for  the  13-year   transition  period  as  discussed  below;
deregulation  of  metering  and  billing;  a 0.5  mills  per  kwh  wires  charge
applicable  to all  retail  customers  for the period  January  1, 2001  through
December  31,  2010  intended  to provide  for  recovery  of any  stranded  cost
including  net  regulatory  assets;  establishment  by  the  Company  of a  rate
stabilization  deferral  balance  of $81  million  by the end of year ten of the
transition  period to be used as determined by the WVPSC to offset market prices
paid for  electricity  in the  eleventh,  twelfth,  and  thirteenth  year of the
transition  period by  residential  and small  commercial  customers that do not
choose an alternative supplier.

        Default rates for residential and small commercial  customers are capped
for four years after the  starting  date and then  increase as  specified in the
plan  for the next six  years.  In years  eleven,  twelve  and  thirteen  of the
transition  period,  the power  supply  rate  shall  equal the  market  price of
comparable  power.  Default rates for industrial and large commercial  customers
are discounted by 1% for four and a half years, beginning July 1, 2000, and then
increase at pre-defined  levels for the next three years.  After seven years the
power supply rate for industrial and large  commercial  customers will be market
based.  The Company's Joint  Stipulation  agreement,  discussed in Note 5 above,
which was approved by the WVPSC on June 2, 2000 in  connection  with a base rate
filing, also provides additional  mechanisms to recover the Company's regulatory
assets.

APCo Discontinues Application of SFAS 71

        In  June  2000  APCo  discontinued  the  application  of SFAS 71 for the
Virginia and West  Virginia  retail  jurisdictional  portions of its  generation
business since generation is no longer considered to be cost-based  regulated in
those  jurisdictions.  The  discontinuance  in the  West  Virginia  jurisdiction
resulted  from  the  June  2,  2000  approval  of the  Joint  Stipulation  which
established rates, wires charges and regulatory asset recovery procedures during
the transition period to market rates. APCo discontinued  application of SFAS 71
for the generation portion of its Virginia retail  jurisdiction after management
decided that it would not request capped rates different from its current rates.
The  existence  of  effective  restructuring  legislation  in  Virginia  and the
probability that the West Virginia  legislation  would become effective with the
passage of required tax legislation in 2001 supported  management's  decision to
discontinue SFAS 71 regulatory accounting.  APCo's discontinuance of SFAS 71 for
generation  resulted in an extraordinary gain of $9 million because
management  believes that all net regulatory  assets related to the Virginia and
West Virginia  generation  business will be recovered.  Under the  provisions of
EITF 97-4, APCo's  generation-related  net regulatory assets were transferred to
the transmission and distribution  portion of the business and will be amortized
as they are recovered through charges to customers. APCo performed an accounting
impairment  analysis of generation assets under SFAS 121 and concluded there was
no impairment of generation assets.

Ohio Restructuring Law and Transition Plan Filings

        A discussed in Note 5 of the Notes to Consolidated  Financial Statements
in the 1999 Annual Report, the Ohio Electric Restructuring Act of 1999 (the Act)
provides for, among other things,  customer  choice of electricity  supplier,  a
residential  rate  reduction  of 5% for the  generation  portion  of rates and a
freezing of generation  rates including fuel rates beginning on January 1, 2001.
The Act also provides for a five-year  transition period to move from cost based
rates to market  pricing  for  generation  services.  It  authorizes  the Public
Utilities  Commission of Ohio (PUCO) to address certain major transition  issues
including unbundling of rates and the recovery of transition costs which include
regulatory  assets,  generating  asset  impairments  and other  stranded  costs,
employee  severance and retraining  costs,  consumer  education  costs and other
costs. Stranded costs are generation costs that are not deemed to be recoverable
in a competitive market.

        On March 28,  2000,  the PUCO staff  issued its report on the  Company's
transition  plan filings for its  subsidiaries,  Ohio Power  Company  (OPCo) and
Columbus  Southern Power Company (CSP). On May 8, 2000, a stipulation  agreement
between the  Company,  the PUCO  staff,  the Ohio  Consumers'  Counsel and other
concerned  parties was filed with the PUCO for approval.  The key  provisions of
the stipulation agreement are:

o    Recovery of generation-related  regulatory assets over seven years for OPCo
     and eight years for CSP through frozen  transition rates for the first five
     years of the recovery period and a wires charge for the remaining years.

o    A shopping  incentive  (a price  credit) of 2.5 mills per kwh for the first
     25% of  CSP  residential  customers  that  switch  suppliers.  There  is no
     shopping incentive for OPCo customers.

o    The  absorption of $40 million by CSP and OPCo ($20 million per Company) of
     consumer  education,  implementation  and transition plan filing costs with
     deferral of the remaining costs,  plus a carrying  charge,  as a regulatory
     asset for recovery in future distribution rates.

o    The companies  will make available a fund of up to $10 million to reimburse
     customers  who chose to  purchase  their  power from  another  company  for
     certain  transmission  charges imposed by Pennsylvania-New  Jersey-Maryland
     transmission   organization  (PJM)  and/or  a  midwest  independent  system
     operator (Midwest ISO) on generation  originating in the Midwest ISO or PJM
     areas.

o        The  statutory 5% reduction in the  generation  component of
     residential  tariffs will remain in effect for the entire 5 year
     transition period.
o        The companies'  request for a $90 million gross receipts tax rider to
     recover  duplicate  gross receipts tax will be litigated
     separately.


<PAGE>


        Hearings on the stipulation and the gross receipts tax issue were held
in June 2000.  Approval of the stipulation  agreement by
the PUCO and a decision on the gross receipts tax issue are pending.
Potential For Write Offs In The Ohio Jurisdiction
        Management  has concluded that as of June 30, 2000 the  requirements  to
apply  SFAS  71  continue  to be met in the  Ohio  jurisdiction.  The  Company's
accounting for generation  will continue to be in accordance with SFAS 71 in the
Ohio jurisdiction and will continue to be considered to be cost-based  regulated
for accounting  purposes until the amount of transition  rates and stranded cost
wires charges are determined and known.  OPCo and CSP will therefore,  be unable
to discontinue SFAS 71 regulatory  accounting until the stipulation agreement is
approved and/or the PUCO issues its  restructuring  order. The law requires that
the PUCO issue such an order no later than October 2000.

        Upon the  discontinuance  of SFAS 71 the Company  will have to write off
its Ohio jurisdictional  generation-related regulatory assets to the extent that
they cannot be recovered  under the frozen  transition  rates and stranded costs
distribution  wires  charges  and record any asset  accounting  impairments.  An
impairment  loss would be  recorded,  under SFAS No. 121, to the extent that the
cost  of   generation   assets  cannot  be  recovered   through   non-discounted
generation-related  revenues  during the  transition  period  and future  market
prices.

        The amount of regulatory  assets  recorded on the books at June 30, 2000
applicable to the Ohio retail jurisdictional generating business is $757 million
before  related  tax  effects.  Due  to the  planned  closing  of the  Company's
affiliated  mines,  including  the  Meigs  mine,  projected   generation-related
regulatory   assets  as  of  December  31,  2000  (the  date  that   recoverable
generation-related  regulatory assets are measured under the Ohio law) allocable
to the Ohio retail  jurisdiction  are estimated to exceed $800  million,  before
income tax  effects.  Recovery of these  regulatory  assets is being sought as a
part of the Company's  Ohio  transition  plan filings and is provided for by the
stipulation  agreement  presently  before  the  PUCO  for  approval.   Based  on
transition  rates and wires charges  currently in the stipulation  agreement and
management's  current  projections of future market prices,  management does not
anticipate that the Company will experience a material tangible asset accounting
impairment or regulatory asset  write-offs.  Whether the Company will experience
material  regulatory  asset  write-offs will depend on whether the PUCO approves
the Company's stipulation agreement which provides for their recovery.

        A  determination  of  whether  the  Company  will  experience  any asset
impairment loss regarding its Ohio retail  jurisdictional  generating assets and
any loss from a possible inability to recover Ohio generation-related regulatory
assets  and  other  transition  costs  cannot  be made  until  such  time as the
transition  rates and the wires charges are  determined  through the  regulatory
process.  In the event the  Company is unable to recover all or a portion of its
generation-related  regulatory assets, stranded costs and other transition costs
including the  duplicate  gross  receipts tax, it could have a material  adverse
effect on results of operations, cash flows and possibly financial condition.

Texas and Arkansas Restructuring

        In June 1999 restructuring legislation was signed into law in Texas that
will restructure the electric utility  industry (Texas  Legislation).  The Texas
Legislation,  among other  things:  o gives Texas  customers  of  investor-owned
utilities the opportunity to choose their electric provider beginning January 1,

             2002;

o            provides  for  the  recovery  of  regulatory  assets  and of  other
             stranded  costs through  securitization  and  non-bypassable  wires
             charges;

o        requires reductions in nitrogen oxide and sulfur dioxide emissions;
o            provides a rate freeze until  January 1, 2002 followed by a 6% rate
             reduction  for  residential  and  small  commercial  customers,  an
             additional rate reduction for low-income  customers and a number of
             customer protections;

o sets an earnings test for the three years of rate freeze (1999 through  2001);
o sets  certain  limits for  ownership  and  control of  generation  capacity by
companies; and

o            requires a filing after January 10, 2004 to finalize stranded costs
             (2004 true-up  proceeding)  including final fuel recovery balances,
             regulatory assets, certain environmental costs,  accumulated excess
             earnings and other issues.

     Delivery of electricity will continue to be the responsibility of the local
electric transmission and distribution utility company at regulated prices. Each
electric  utility must submit a plan to unbundle its business  activities into a
retail electric  provider,  a power  generation  company and a transmission  and
distribution utility.

     In  1999   legislation   was  enacted  in  Arkansas  that  will  ultimately
restructure the electric utility industry (Arkansas  Legislation).  Major points
of the Arkansas Legislation are: o Retail competition begins January 1, 2002 but
can be delayed until as late as June 30, 2003 by the Arkansas Public Service

             Commission (Arkansas Commission).
o Transmission facilities must be operated by an ISO if owned by a company which
also owns  generation  assets.  o Rates will be frozen for one to three years. o
Market power issues will be addressed by the Arkansas Commission.

     SWEPCo filed a business unbundling plan in Arkansas on June 30, 2000.

     CPL, SWEPCo and WTU filed their business separation (unbundling) plans with
the Texas Commission on January 10, 2000. The filings  described a financial and
accounting  functional  separation  but not a legal  or  structural  separation,
described how  operations  will be physically  separated and the functions  they
will perform,  described  competitive  energy  services,  and provided a code of
conduct.  In March 2000, the Texas Commission ruled that the subsidiaries' plans
were not in compliance  with the Texas  Legislation and ordered revised plans be
submitted  to  separate  the  generation  business  from the wires  business  in
separate  legal  entities by January 1, 2002.  In May 2000 a revised  separation
plan was  filed,  which  the  Texas  Commission  approved  on July 7, 2000 in an
interim order.

         Under the Texas Legislation,  electric utilities are allowed,  with the
approval  of  the  Texas   Commission,   to  recover  stranded  costs  including
generation-related  regulatory  assets that may not be  recoverable  in a future
competitive market. The approved costs can be refinanced through securitization,
which is a  financing  structure  designed  to  provide  state  sponsored  lower
financing  costs  than  are  available  through   conventional   public  utility
financings.  The securitized  amounts plus interest are then recovered through a
non-bypassable  wires charge.  In 1999 CPL filed an  application  with the Texas
Commission   to   securitize   approximately   $1.27   billion   of  its  retail
generation-related  regulatory  assets and  approximately  $47  million in other
qualified restructuring costs.

         On February  10,  2000,  the Texas  Commission  tentatively  approved a
settlement,  which will permit CPL to securitize  approximately  $764 million of
net regulatory assets. The Texas Commission's order authorized issuance of up to
$797 million of securitization  bonds including the $764 million for recovery of
net regulatory assets and $33 million for other qualified refinancing costs. The
$764 million for recovery of net regulatory assets reflects the recovery of $949
million  of  regulatory  assets  offset by $185  million  of  customer  benefits
associated with accumulated  deferred income taxes. CPL had previously  proposed
in its filing to flow these  benefits back to customers over the 14-year term of
the securitization  bonds. The remaining  regulatory assets originally requested
by CPL in its 1999  securitization  request  has been  included  in a March 2000
filing with the Texas  Commission,  requesting  recovery of an  additional  $1.1
billion of  stranded  costs.  The March 2000  filing for $1.1  billion  includes
recovery of  approximately  $800 million of South Texas  Project  (STP)  nuclear
plant  costs  included  in utility  plant on the  Balance  Sheet and  previously
identified  as "Excess  Cost Over  Market"  (ECOM) by the Texas  Commission  for
regulatory purposes. A final determination on recovery will occur as part of the
2004 true-up proceeding and the total amount recoverable can be securitized.

         On April  11,  2000,  four  parties  appealed  the  Texas  Commission's
securitization  order to the Travis County District Court.  One of these appeals
challenges  the  ability  to  recover  securitization  charges  under  the Texas
Constitution. CPL will not be able to issue the securitization bonds until these
appeals are resolved. As a result, the securitization bonds are not likely to be
issued until 2001.

         The  financial  statements  of CPL,  SWEPCo  and WTU have  historically
reflected  the effects of applying the  requirements  of SFAS 71. As a result of
the scheduled  deregulation of generation in Texas and Arkansas, the application
of SFAS 71 for the  generation  portion  of the  business  in those  states  was
discontinued   in   1999.   Under   the   provisions   of   EITF   97-4,   CPL's
generation-related  net regulatory  assets were  transferred to the transmission
and  distribution  portion of the  business  and will be  amortized  as they are
recovered through charges to customers.  Management  believes that substantially
all of  CPL's  generation-related  regulatory  assets  should  be  recovered  as
provided by the Texas  Legislation when an electric utility has a stranded cost.
If future  events were to occur that made the recovery of  regulatory  assets no
longer  probable,  CPL  would  write-off  the  portion  of  such  assets  deemed
unrecoverable as a non-cash charge to earnings.

     CPL's recovery of  generation-related  regulatory assets and stranded costs
are subject to a final  determination by the Texas Commission in 2004. The Texas
Legislation  provides that all such finally  determined  stranded  costs will be
recovered. Since SWEPCo and WTU are not expected to have net stranded costs, all
generation-related  non-recoverable  net  regulatory  assets were written off in
1999 when they  discontinued  application of SFAS 71 regulatory  accounting.  An
impairment  analysis for generation assets under SFAS 121 was completed for CPL,
SWEPCo and WTU which concluded there was no accounting  impairment of generation
assets when the application of SFAS 71 was discontinued.  An impairment analysis
involves  estimating  future net cash flows arising from the use of an asset. If
the  undiscounted  net cash flows  exceed the net book value of the asset,  then
there is no impairment of the asset to record for accounting purposes.  CPL,
SWEPCo and WTU will test their  generation  assets for  impairment  under
SFAS 121 when  circumstances change.  However,  on a  discounted  basis the
cash  flows  are less than  CPL's generating  asset's  net book  value and
together  with its  generation-related regulatory   assets  create  a
recoverable   stranded  cost  under  the  Texas Legislation.

         The Texas  Legislation  also  provides  that each year  during the 1999
through 2001 rate freeze period,  electric  utilities are subject to an earnings
test. For electric  utilities with stranded costs,  such as CPL, any earnings in
excess of the most recently  approved cost of capital in its last rate case must
be applied to reduce stranded costs.  Utilities  without stranded costs, such as
SWEPCo and WTU,  must either flow such amounts back to customers or make capital
expenditure to improve transmission or distribution facilities or to improve air
quality.

         A Texas settlement  agreement in connection with the AEP and CSW merger
permits CPL to apply for regulatory purposes up to $20 million of STP ECOM Plant
assets a year in 2000 and 2001 to reduce excess earnings,  if any. For book
purposes, plant assets will be depreciated on a systematic and rational basis
unless impaired. To the extent excess  earnings  exceed  $20  million  in 2000
or 2001  CPL  will  establish  a regulatory liability by a charge to earnings.

        Beginning  January  1,  2002,  fuel  costs  will not be subject to Texas
Commission fuel reconciliation  proceedings.  Consequently,  CPL, SWEPCo and WTU
will file a final fuel reconciliation with the Texas Commission 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  Company  continues  to  analyze  the  impact of the  electric  utility
industry  restructuring  legislation  on the Texas electric  utility  companies.
Although  management  believes  that the  Texas  Legislation  provides  for full
recovery of the  Company's  stranded  costs and that the Company does not have a
recordable  accounting  impairment a final  determination of whether the Company
will   experience   any   accounting   loss  from  an   inability   to   recover
generation-related  regulatory assets and other  restructuring  related costs in
Texas and  Arkansas  cannot be made  until such time as the  litigation  and the
regulatory  process are complete following the 2004 true-up  proceeding.  In the
event the Company is unable after the 2004 true-up  proceeding to recover all or
a portion of its generation-related  regulatory assets, stranded costs and other
restructuring  related costs, it could have a material adverse effect on results
of operations, cash flows and possibly financial condition.

COLI Litigation

        As discussed in Note 6 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report,  the  deductibility  of certain  interest  deductions
related to AEP?s corporate owned life insurance (COLI) program for taxable years
1991  through  1996 is under  review  by the  Internal  Revenue  Service  (IRS).
Adjustments  have been or will be proposed by the IRS disallowing  COLI interest
deductions. A disallowance of the COLI interest deductions through June 30, 2000
would reduce earnings by approximately $318 million (including interest).

        The Company  made  payments of taxes and interest  attributable  to COLI
interest  deductions  for taxable years 1991 through 1998 to avoid the potential
assessment  by the IRS of any  additional  above  market  rate  interest  on the
contested  amount.  The  payments to the IRS are  included  on the  consolidated
balance sheet in other assets pending the resolution of this matter. The Company
is seeking refund through litigation of all amounts paid plus interest.

        In order to resolve  this  issue,  the  Company  filed suit  against the
United States in the U.S.  District  Court for the Southern  District of Ohio in
1998.  In 1999 a U.S.  Tax  Court  judge  decided  in the  Winn-Dixie  Stores v.
Commissioner case that a corporate  taxpayer's COLI interest deduction should be
disallowed.  Notwithstanding the Tax Court's decision in Winn-Dixie,  management
has made no provision for any possible  adverse earnings impact from this matter
because it  believes,  and has been  advised by outside  counsel,  that it has a
meritorious  position and will vigorously  pursue its lawsuit.  In the event the
resolution of this matter is unfavorable, it will have a material adverse impact
on results of operations, cash flows and possibly financial condition.

Shareholders' Litigation

        On June 23, 2000, a complaint was filed in the U.S.  District  Court for
the  Eastern  District  of New York  seeking  unspecified  compensatory  damages
against  the  Company  and four  former  or  present  officers.  The  individual
plaintiff also seeks  certification as the  representative of a class consisting
of all persons and entities who purchased or otherwise acquired AEP common stock
between  July 25,  1997,  and June 25,  1999.  The  complaint  alleges  that the
defendants   knowingly   violated  federal   securities  laws  by  disseminating
materially false and misleading statements  concerning,  among other things, the
undisclosed  materially  impaired  condition  of the  Cook  Nuclear  Plant,  the
Company's inability to properly monitor, manage, repair, supervise and report on
operations  at the  Cook  Plant  and the  materially  adverse  conditions  these
problems were having, and would continue to have, on the Company's deteriorating
financial condition,  and ultimately on the Company's operations,  liquidity and
stock price.  Three other similar class action complaints have been filed and it
is  anticipated  that  the  court  will  consolidate  the  various   complaints.
Management  believes these shareholder  actions are without merit and intends to
oppose them vigorously.

CPL Municipal Franchise Fee Litigation

        CPL has been involved in litigation  regarding  municipal franchise fees
in Texas as a result of a class action suit filed by the City of San Juan, Texas
in 1996. The City of San Juan claims CPL underpaid  municipal franchise fees and
seeks  damage  of  up  to  $300  million  plus  attorney's  fees.  CPL  filed  a
counterclaim for overpayment of franchise fees.

        During 1997, 1998 and 1999 the litigation moved procedurally through the
Texas Court System and was sent to mediation without resolution.

        In 1999 a class  notice was mailed to each of the cities  served by CPL.
Over 90 of the  128  cities  served  declined  to  participate  in the  lawsuit.
However, CPL has pledged that if any final, non-appealable court decision in the
litigation awards a judgement against CPL for a franchise underpayment, CPL will
extend  the  principles  of  that   decision,   with  regard  to  the  franchise
underpayment,  to the cities that decline to participate in the  litigation.  In
December  1999,  the court ruled that the class of  plaintiffs  would consist of
approximately 30 cities. A trial date for June 2001 has been set.

        Although CPL believes  that it has  substantial  defenses to the cities'
claims and intends to defend  itself  against the cities'  claims and pursue its
counterclaims  vigorously,   management  cannot  predict  the  outcome  of  this
litigation or its impact on the Company's  results of operations,  cash flows or
financial condition.

Federal EPA Complaint and Notice of Violation

        As  discussed  in MDA in the 1999  Annual  Report,  the Company has been
involved  in  litigation  regarding  generating  plant  emissions.   Notices  of
Violation  were  issued  and a  complaint  was  filed by the U.S.  Environmental
Protection  Agency  (Federal  EPA) in the U.S.  District  Court that alleges the
Company and eleven unaffiliated utilities made modifications to generating units
at certain of their coal-fired  generating plants over the course of the past 25
years that extend unit  operating  lives or increase  unit  generating  capacity
without  a  preconstruction  permit  in  violation  of the  Clean  Air Act.  The
complaint was amended in March 2000 to add  allegations  for certain  generating
units  previously  named in the complaint and to include  additional  AEP System
generating  units  previously  named  only in the  Notices of  Violation  in the
complaint.  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.

        A number of  northeastern  and  eastern  states  were  granted  leave to
intervene in the Federal  EPA's action  against the Company  under the Clean Air
Act. A lawsuit  against  power  plants  owned by the  Company  alleging  similar
violations  to those in the Federal EPA  complaint  and Notices of Violation was
filed by a number of special interest groups and has been  consolidated with the
Federal EPA action.

        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). Civil penalties,  if ultimately imposed by the court, and the cost of any
required new pollution  control  equipment,  if the court accepts  Federal EPA's
contentions, could be substantial.

        On May 10, 2000, the Company filed motions to dismiss all or portions of
the  complaints.  Briefing  on these  motions was  completed  on August 2, 2000.
Management believes its maintenance,  repair and replacement  activities were in
conformity  with the Clean Air Act and intends to vigorously  pursue its defense
of this matter.

        In the event the Company  does 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 where states are deregulating generation, unbundled
transition  period  generation  rates,  stranded  cost wires  charges and future
market prices for electricity. NOx Reductions

        As discussed in MDA in the 1999 Annual Report,  Federal EPA had issued a
final rule (the NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states,  including certain states in which the AEP
System's generating plants are located. A number of utilities, including certain
AEP System companies,  had filed petitions seeking a review of the final rule in
the U.S. Court of Appeals for the District of Columbia  Circuit (Appeals Court).
In May 1999, the Appeals Court  indefinitely  stayed the requirement that states
develop  revised air quality  programs to impose the NOx reductions but did not,
however,  stay the  final  compliance  date of May 1,  2003.  In March  2000 the
Appeals Court issued a decision  generally  upholding the NOx rule. On April 20,
2000,  certain AEP System companies and other petitioners filed for rehearing of
this decision  including a rehearing by the entire  Appeals  Court.  On June 22,
2000,  the Appeals  Court denied the petition for  rehearing and lifted the stay
related to the states' development of revised air quality programs to impose the
NOx reductions. The petition for a rehearing before the entire Appeals Court was
also denied.  The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.

        In a related  matter,  on April 19,  2000,  the Texas  Natural  Resource
Conservation   Commission  adopted  rules  (TNRCC  rule)  requiring  significant
reductions in NOx emissions from utility sources,  including SWEPCo and CPL. The
TNRCC rule's compliance date is May 2003 for CPL and 2005 for SWEPCo.  The TNRCC
rule is being challenged in state court by an unaffiliated utility.

        Preliminary  estimates indicate that compliance with the NOx rule upheld
by the Appeals Court as well as  compliance  with the TNRCC rule could result in
required  capital  expenditures of  approximately  $1.8 billion for the Company.
Since  compliance  costs cannot be estimated with certainty,  the actual cost to
comply could be significantly  different than the Company's preliminary estimate
depending upon the compliance alternatives selected to achieve reductions in NOx
emissions.  Unless the  depreciation  of such costs are recovered from customers
through  regulated  rates and/or  future  market  prices for  electricity  where
generation is deregulated, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition. Market Risks

        The Company has certain market risks inherent in its business activities
from changes in electricity  commodity  prices,  foreign currency exchange rates
and interest rates.  Market risk represents the risk of loss that may impact the
Company due to adverse  changes in commodity  market  prices,  foreign  currency
exchange rates and interest  rates.  The Company's  exposure to market risk from
the trading of  electricity  and natural  gas and related  financial  derivative
instruments  was less  than $28  million  at June 30,  2000 and $14  million  at
December 31, 1999 based on the use of a risk measurement  model which calculates
Value at Risk (VaR).  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 three-day holding period.

        There  have  been no  material  changes  to the  Company's  exposure  to
fluctuations in foreign currency  exchange rates related to foreign ventures and
investments since December 31, 1999.

        The exposure to changes in interest rates from the Company's  short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.


<PAGE>
<TABLE>
<CAPTION>


                             AEP GENERATING COMPANY

                              STATEMENTS OF INCOME

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           ------------------     --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)

<S>                                        <C>        <C>         <C>         <C>
OPERATING REVENUES . . . . . . . . . . .   $56,928    $51,612     $113,794    $104,439
                                           -------    -------     --------    --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    26,048     20,169       50,483      40,427
  Rent - Rockport Plant Unit 2 . . . . .    17,070     17,070       34,141      34,141
  Other Operation. . . . . . . . . . . .     1,956      2,092        5,054       5,462
  Maintenance. . . . . . . . . . . . . .     3,166      4,489        5,681       6,751
  Depreciation . . . . . . . . . . . . .     5,541      5,483       11,046      10,923
  Taxes Other Than Federal Income Taxes.     1,124      1,253        2,250       2,492
  Federal Income Taxes . . . . . . . . .       277         54          998         881
                                           -------    -------     --------    --------

          TOTAL OPERATING EXPENSES . . .    55,182     50,610      109,653     101,077
                                           -------    -------     --------    --------

OPERATING INCOME . . . . . . . . . . . .     1,746      1,002        4,141       3,362

NONOPERATING INCOME. . . . . . . . . . .       900        889        1,769       1,745
                                           -------    -------     --------    --------

INCOME BEFORE INTEREST CHARGES . . . . .     2,646      1,891        5,910       5,107

INTEREST CHARGES . . . . . . . . . . . .       993        669        1,812       1,271
                                           -------    -------     --------    --------

NET INCOME . . . . . . . . . . . . . . .   $ 1,653    $ 1,222     $  4,098    $  3,836
                                           =======    =======     ========    ========



                         STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           ------------------     --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . .    $4,183    $4,311       $3,673      $2,770

NET INCOME . . . . . . . . . . . . . . .     1,653     1,222        4,098       3,836

CASH DIVIDENDS DECLARED. . . . . . . . .      -        1,073        1,935       2,146
                                            ------    ------       ------      ------

BALANCE AT END OF PERIOD . . . . . . . .    $5,836    $4,460       $5,836      $4,460
                                            ======    ======       ======      ======



The common  stock of the  Company is wholly  owned by  American  Electric  Power
Company, Inc.

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


                             AEP GENERATING COMPANY

                                 BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                           <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .   $635,273       $629,286
  General . . . . . . . . . . . . . . . . . . . . . . . . .      2,578          2,400
  Construction Work in Progress . . . . . . . . . . . . . .      2,578          8,407
                                                              --------       --------

          Total Electric Utility Plant. . . . . . . . . . .    640,429        640,093

  Accumulated Depreciation. . . . . . . . . . . . . . . . .    304,278        295,065
                                                              --------       --------


          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .    336,151        345,028
                                                              --------       --------

CURRENT ASSETS:

  Cash and Cash Equivalents . . . . . . . . . . . . . . . .         41            317
  Accounts Receivable:
    Affiliated Companies. . . . . . . . . . . . . . . . . .     19,147         22,464
    Miscellaneous . . . . . . . . . . . . . . . . . . . . .      2,617          2,643
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .     18,785         17,505
  Materials and Supplies. . . . . . . . . . . . . . . . . .      4,279          3,966
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .         70            150
                                                              --------       --------


          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     44,939         47,045
                                                              --------       --------


REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      5,624          5,744
                                                              --------       --------


DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      2,416            823
                                                              --------       --------




            TOTAL . . . . . . . . . . . . . . . . . . . . .   $389,130       $398,640
                                                              ========       ========

See Notes to Financial Statements.

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


                             AEP GENERATING COMPANY

                                 BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                           <C>            <C>
  Common Stock - Par Value $1,000:
    Authorized and Outstanding - 1,000 Shares . . . . . . .   $  1,000       $  1,000
  Paid-in Capital . . . . . . . . . . . . . . . . . . . . .     26,300         29,235
  Retained Earnings . . . . . . . . . . . . . . . . . . . .      5,836          3,673
                                                              --------       --------

          TOTAL CAPITALIZATION AND
                 COMMON SHAREHOLDER'S EQUITY . . . . . . . . . .     33,136         33,908
                                                                   --------       --------

OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . .        475            592
                                                              --------       --------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .     44,804         44,800
  Short-term Debt - Notes Payable . . . . . . . . . . . . .       -            24,700
  Advances from Affiliates. . . . . . . . . . . . . . . . .     37,870           -
  Accounts Payable:
    General . . . . . . . . . . . . . . . . . . . . . . . .      7,207          7,539
    Affiliated Companies. . . . . . . . . . . . . . . . . .      4,221         19,451
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      6,818          4,285
  Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . .      4,963          4,963
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      3,075          4,763
                                                              --------       --------

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .    108,958        110,501
                                                              --------       --------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . .    124,974        127,759
                                                              --------       --------

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits . . . . . . . . . . . . .     61,440         63,114
  Amounts Due to Customers for Income Taxes . . . . . . . .     25,107         26,266
                                                              --------       --------

          TOTAL REGULATORY LIABILITIES. . . . . . . . . . .     86,547         89,380
                                                              --------       --------

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     34,890         36,500
                                                              --------       --------

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

CONTINGENCIES (Note 3)

            TOTAL . . . . . . . . . . . . . . . . . . . . .   $389,130       $398,640
                                                              ========       ========

See Notes to Financial Statements.

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


                             AEP GENERATING COMPANY

                            STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                  Six Months Ended

                                    June 30,

                                                                2000           1999
                                                                ----           ----
                                                                   (in thousands)

<S>                                                           <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $  4,098       $  3,836
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . . .    11,046         10,923
    Deferred Federal Income Taxes. . . . . . . . . . . . . .    (2,769)        (2,661)
    Deferred Investment Tax Credits. . . . . . . . . . . . .    (1,674)        (1,677)
    Amortization of Deferred Gain on Sale
      and Leaseback - Rockport Plant Unit 2. . . . . . . . .    (2,785)        (2,785)
    Deferred Property Taxes. . . . . . . . . . . . . . . . .    (1,648)        (1,666)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable. . . . . . . . . . . . . . . . . . .     3,343            936
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    (1,593)       (15,480)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .   (15,562)         6,496
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .     2,533          4,477
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .    (1,270)        (3,413)
                                                              --------       --------
        Net Cash Flows Used For Operating Activities . . . .    (6,281)        (1,014)
                                                              --------       --------

INVESTING ACTIVITIES - Construction Expenditures . . . . . .    (2,295)        (4,436)
                                                              --------       --------

FINANCING ACTIVITIES:
  Return of Capital to Parent Company. . . . . . . . . . . .    (2,935)        (6,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .   (24,700)        14,925
  Change in Advances from Affiliates (net) . . . . . . . . .    37,870           -
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .    (1,935)        (2,146)
                                                              --------       --------
        Net Cash Flows From Financing Activities . . . . . .     8,300          6,779
                                                              --------       --------

Net Increase (Decrease) in Cash and Cash Equivalents . . . .      (276)         1,329
Cash and Cash Equivalents at Beginning of Period . . . . . .       317            232
                                                              --------       --------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $     41       $  1,561
                                                              ========       ========


Supplemental Disclosure:
  Cash  paid  for  interest  net  of  capitalized  amounts  was  $1,619,000  and
  $1,070,000  and for income taxes was  $3,129,000  and  $1,268,000  in 2000 and
  1999, respectively.

See Notes to Financial Statements.

</TABLE>
<PAGE>



                             AEP GENERATING COMPANY
                          NOTES TO FINANCIAL STATEMENTS
                                  JUNE 30, 2000

                                   (UNAUDITED)

1.      GENERAL

        The  accompanying  unaudited  financial  statements  should  be  read in
conjunction  with the 1999 Annual Report as  incorporated  in and filed with the
Form 10-K. In the opinion of management,  the financial  statements  reflect all
adjustments  (consisting of only normal recurring  accruals) which are necessary
for a fair presentation of the results of operations for interim periods.

2.      MONEY POOL

        On June 15,  2000,  the Company  became a  participant  in the  American
Electric  Power  (AEP)  System  Money  Pool  (Money  Pool).  The Money Pool is a
mechanism   structured  to  meet  the  short-term   cash   requirements  of  the
participants with AEP Company,  Inc. acting as the primary borrower on behalf of
the Money Pool. The Company's affiliates that are U.S. domestic electric utility
operating companies are the primary participants in the Money Pool.

        The  operation  of the Money Pool is  designed to match on a daily basis
the available cash and borrowing requirements of the participants.  Participants
with  excess cash loan funds to the Money Pool  reducing  the amount of external
funds AEP  Company,  Inc.  needs to borrow  and other  participants  meet  their
short-term  cash  requirements  with advances from the Money Pool.  AEP Company,
Inc. borrows the funds needed on a daily basis to meet the net cash requirements
of the Money Pool participants.  A weighted average daily interest rate which is
calculated  based on the  outstanding  short-term  debt  borrowings  made by AEP
Company,  Inc.  is applied to each Money Pool  participant's  daily  outstanding
investment or debt position to determine  interest  income or interest  expense.
Interest  income is included in  nonoperating  income,  and interest  expense is
included in interest charges.  As a result of becoming a Money Pool participant,
the Company retired its short-term debt and reports its borrowing from the Money
Pool as Advances from Affiliates on the Balance Sheets.

3.      CONTINGENCIES

NOx Reductions

        As discussed in Note 3 of the Notes of Financial  Statements of the 1999
Annual Report,  the United States  Environmental  Protection Agency had issued a
final rule (the NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states,  including certain states in which the AEP
System?s generating plants are located. A number of utilities, including certain
AEP System companies,  had filed petitions seeking a review of the final rule in
the U.S. Court of Appeals for the District of Columbia  Circuit (Appeals Court).
In May 1999, the Appeals Court  indefinitely  stayed the requirement that states
develop  revised air quality  programs to impose the NOx reductions but did not,
however,  stay the  final  compliance  date of May 1,  2003.  In March  2000 the
Appeals Court issued a decision  generally  upholding the NOx rule. On April 20,
2000,  certain AEP System companies and other petitioners filed for rehearing of
this decision  including a rehearing by the entire  Appeals  Court.  On June 22,
2000,  the Appeals  Court denied the petition for  rehearing and lifted the stay
related to the states' development of revised air quality programs to impose the
NOx reductions. The petition for a rehearing before the entire Appeals Court was
also denied.  The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.

        Preliminary  estimates indicate that compliance with the NOx rule upheld
by  the  Appeals  Court  could  result  in  required  capital   expenditures  of
approximately  $125 million for the Company.  Since  compliance  costs cannot be
estimated  with  certainty,  the actual  cost to comply  could be  significantly
different than the Company's  preliminary estimate depending upon the compliance
alternatives selected to achieve reductions in NOx emissions.  Unless such costs
are recovered from customers  through  regulated  rates and/or  reflected in the
future market price of electricity if generation is deregulated,  they will have
an adverse  effect on future  results  of  operations,  cash flows and  possibly
financial condition.


<PAGE>



                             AEP GENERATING COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
                     ---------------------------------------

        Operating  revenues are derived  from the sale of Rockport  Plant energy
and capacity to two affiliated  companies and in 1999 one  unaffiliated  utility
pursuant to Federal Energy Regulatory  Commission (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  increased  $0.4  million  or 35%  for  the  second  quarter
primarily as a result of the effect of a reduction in the April 1999 billings to
reflect an adjustment to actual for estimated power production expenses included
in March 1999 billings.  The 1999 adjustment to actual expenses reduced revenues
and net income for the second  quarter of 1999.  Also  contributing  to the $0.3
million or 7% increase in net income for the year-to-date  period was the effect
of expenses incurred in 1999 that were included in billing in the fourth quarter
of 1999.

        Income statement line items which changed significantly were:

                                     Increase (Decrease)

                            Second Quarter     Year-to-Date

                            (in millions)   %  (in millions)   %

Operating Revenues . . . . .    $ 5.3      10      $ 9.4       9
Fuel Expense . . . . . . . .      5.9      29       10.1      25
Other Operation Expense. . .     (0.1)     (6)      (0.4)     (7)
Maintenance Expense. . . . .     (1.3)    (29)      (1.1)    (16)
Taxes Other Than Federal
  Income Taxes . . . . . . .     (0.1)    (10)      (0.2)    (10)
Federal Income Taxes . . . .      0.2     N.M.       0.1      13
Net Interest Charges . . . .      0.3      48        0.5      43

N.M. = Not Meaningful

        The increase in operating  revenues resulted  primarily from an increase
in recoverable  expenses as generation  increased due to the availability of the
Rockport Plant. In 1999 planned  maintenance outages reduced the availability of
the Rockport Plant units.  Shorter  outages in the first and second  quarters of
2000 allowed the Rockport  units to generate 22% more  electricity  in the first
six months of 2000 than in 1999.

        Fuel expense increased due to the increase in generation  reflecting the
        increased availability of the Rockport Plant units. The reduction in the
        number of outages and the shorter  length of planned  outages  accounted
        for the decrease in maintenance

expense for the second quarter and year-to-date period.
        Taxes other than  federal  income  taxes  declined  due to a decrease in
state income taxes  attributable to the filing of a consolidated tax return with
an affiliate that had reduced taxable income.

        Federal  income taxes  attributable  to  operations  increased due to an
increase in pre-tax income.

        The  increase in interest  charges was due to an increase in the average
outstanding  short-term debt balances and an increase in average  interest rates
on short-term and variable rate debt  reflecting the Company's  short-term  cash
demands and market conditions for short-term interest rates.


<PAGE>
<TABLE>
<CAPTION>


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                   (UNAUDITED)

                                           Three Months Ended        Six Months Ended

                                                June 30,                  June 30,
                                         ---------------------    ----------------
                                           2000         1999         2000          1999
                                           ----         ----         ----          ----
                                                         (in thousands)

<S>                                      <C>          <C>         <C>          <C>
OPERATING REVENUES . . . . . . . . . . . $430,000     $373,766    $  885,595   $  801,468
                                         --------     --------    ----------   ----------
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   92,663       99,659       191,220      223,232
  Purchased Power. . . . . . . . . . . .  106,410       61,048       198,974      111,639
  Other Operation. . . . . . . . . . . .   61,566       60,162       122,207      122,911
  Maintenance. . . . . . . . . . . . . .   28,989       38,361        57,314       66,872
  Depreciation and Amortization. . . . .   38,899       37,224        77,237       73,775
  Taxes Other Than Federal Income Taxes.   28,817       30,066        59,462       60,041
  Federal Income Taxes . . . . . . . . .   14,448        4,147        42,727       28,292
                                         --------     --------    ----------   ----------
          TOTAL OPERATING EXPENSES . . .  371,792      330,667       749,141      686,762
                                         --------     --------    ----------   ----------
OPERATING INCOME . . . . . . . . . . . .   58,208       43,099       136,454      114,706
NONOPERATING INCOME (LOSS) . . . . . . .    3,427          315         4,208         (773)
                                         --------     --------    ----------   ----------
INCOME BEFORE INTEREST CHARGES . . . . .   61,635       43,414       140,662      113,933
INTEREST CHARGES . . . . . . . . . . . .   31,395       32,378        62,758       63,636
                                         --------     --------    ----------   ----------
INCOME BEFORE EXTRAORDINARY ITEM . . . .   30,240       11,036        77,904       50,297

EXTRAORDINARY GAIN - DISCONTINUANCE OF
 SFAS NO. 71 (INCLUSIVE OF TAX BENEFIT
 OF $7,872,000). . . . . . . . . . . . .    8,938         -            8,938         -
                                         --------     --------    ----------   -------
NET INCOME . . . . . . . . . . . . . . .   39,178       11,036        86,842       50,297
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      632          673         1,265        1,348
                                         --------     --------    ----------   ----------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 38,546     $ 10,363    $   85,577   $   48,949
                                         ========     ========    ==========   ==========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                                           Three Months Ended        Six Months Ended

                                                June 30,                  June 30,
                                         ---------------------    ----------------
                                           2000         1999        2000           1999
                                           ----         ----        ----           ----
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $191,232     $187,699    $175,854       $179,461
NET INCOME . . . . . . . . . . . . . . .   39,178       11,036      86,842         50,297

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   31,653       30,348      63,306         60,696
    Cumulative Preferred Stock . . . . .      525          565       1,050          1,132
  Capital Stock Expense. . . . . . . . .      106          108         214            216
                                         --------     --------    --------       --------

BALANCE AT END OF PERIOD . . . . . . . . $198,126     $167,714    $198,126       $167,714
                                         ========     ========    ========       ========

The common  stock of the  Company is wholly  owned by  American  Electric  Power
Company, Inc.

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


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                            June 30,      December 31,
                                                              2000            1999
                                                           ----------     --------
                                                                 (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                         <C>            <C>
  Production . . . . . . . . . . . . . . . . . . . . .      $2,040,224     $2,014,968
  Transmission . . . . . . . . . . . . . . . . . . . .       1,164,462      1,151,377
  Distribution . . . . . . . . . . . . . . . . . . . .       1,778,715      1,741,685
  General. . . . . . . . . . . . . . . . . . . . . . .         247,847        247,798
  Construction Work in Progress. . . . . . . . . . . .          84,986        107,123
                                                            ----------     ----------
          Total Electric Utility Plant . . . . . . . .       5,316,234      5,262,951
  Accumulated Depreciation and Amortization. . . . . .       2,128,020      2,079,490
                                                            ----------     ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . .       3,188,214      3,183,461
                                                            ----------     ----------



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         299,777        160,546
                                                            ----------     ----------



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .           2,023         64,828
  Advances to Affiliates . . . . . . . . . . . . . . .          12,857           -
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         135,110        109,525
    Affiliated Companies . . . . . . . . . . . . . . .          47,252         37,827
    Miscellaneous. . . . . . . . . . . . . . . . . . .          10,728          9,154
    Allowance for Uncollectible Accounts . . . . . . .          (2,205)        (2,609)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .          49,356         58,161
  Materials and Supplies . . . . . . . . . . . . . . .          57,134         56,917
  Accrued Utility Revenues . . . . . . . . . . . . . .          40,389         53,418
  Energy Trading Contracts . . . . . . . . . . . . . .         986,681        143,777
  Prepayments. . . . . . . . . . . . . . . . . . . . .           7,554          7,713
                                                            ----------     ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . .       1,346,879        538,711
                                                            ----------     ----------


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         448,905        436,894
                                                            ----------     ----------


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .          29,973         34,788
                                                            ----------     ----------

            TOTAL. . . . . . . . . . . . . . . . . . .      $5,313,748     $4,354,400
                                                            ==========     ==========

See Notes to Consolidated Financial Statements.

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


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                          June 30,      December 31,
                                                            2000            1999
                                                         ----------     --------
                                                               (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  30,000,000 Shares

<S>                                                      <C>             <C>
    Outstanding - 13,499,500 Shares. . . . . . . . . .   $  260,458      $  260,458
  Paid-in Capital. . . . . . . . . . . . . . . . . . .      717,464         714,259
  Retained Earnings. . . . . . . . . . . . . . . . . .      198,126         175,854
                                                         ----------      ----------
          Total Common Shareholder's Equity. . . . . .    1,176,048       1,150,571
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .       18,188          18,491
    Subject to Mandatory Redemption. . . . . . . . . .       11,860          20,310
  Long-term Debt . . . . . . . . . . . . . . . . . . .    1,435,207       1,539,302
                                                         ----------      ----------

          TOTAL CAPITALIZATION . . . . . . . . . . . .    2,641,303       2,728,674
                                                         ----------      ----------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .      122,295         132,130
                                                         ----------      ----------

CURRENT LIABILITIES:
  Preferred Stock Due Within One Year. . . . . . . . .        8,450            -
  Long-term Debt Due Within One Year . . . . . . . . .      175,005         126,005
  Short-term Debt. . . . . . . . . . . . . . . . . . .      145,675         123,480
  Accounts Payable - General . . . . . . . . . . . . .       40,039          59,150
  Accounts Payable - Affiliated Companies. . . . . . .       89,137          42,459
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       48,274          49,038
  Customer Deposits. . . . . . . . . . . . . . . . . .       12,769          12,898
  Interest Accrued . . . . . . . . . . . . . . . . . .       18,176          19,079
  Energy Trading Contracts . . . . . . . . . . . . . .      973,727         140,279
  Other. . . . . . . . . . . . . . . . . . . . . . . .       63,408          71,044
                                                         ----------      ----------

          TOTAL CURRENT LIABILITIES. . . . . . . . . .    1,574,660         643,432
                                                         ----------      ----------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      685,551         671,917
                                                         ----------      ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       45,676          57,259
                                                         ----------      ----------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .      244,263         120,988
                                                         ----------      ----------

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .   $5,313,748      $4,354,400
                                                         ==========      ==========

See Notes to Consolidated Financial Statements.

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

                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                    Six Months Ended

                                                                        June 30,
                                                                ----------------
                                                                   2000          1999
                                                                   ----          ----
                                                                     (in thousands)

OPERATING ACTIVITIES:
<S>                                                             <C>           <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . .  $  86,842     $  50,297
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . . .     77,293        74,302
    Deferred Federal Income Taxes. . . . . . . . . . . . . . .     15,054        13,895
    Deferred Investment Tax Credits. . . . . . . . . . . . . .     (2,332)       (2,344)
    Deferred Power Supply Costs (net). . . . . . . . . . . . .    (11,938)       23,208
    Extraordinary Gain - Discontinuance of SFAS No. 71 . . . .     (8,938)         -
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . . .    (36,988)       18,981
    Fuel, Materials and Supplies . . . . . . . . . . . . . . .      8,588       (17,635)
    Accrued Utility Revenues . . . . . . . . . . . . . . . . .     13,029         7,266
    Accounts Payable . . . . . . . . . . . . . . . . . . . . .     27,567       (25,164)
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . . .     (3,321)      (73,030)
  Unrealized Gain on Trading Assets and Liabilities. . . . . .    (19,438)       (6,047)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . . .    (15,855)       (3,081)
                                                                ---------     ---------
        Net Cash Flows From Operating Activities . . . . . . .    129,563        60,648
                                                                ---------     ---------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . . .    (80,870)      (86,808)
  Proceeds from Sale of Property . . . . . . . . . . . . . . .        148           200
                                                                ---------     ---------
        Net Cash Flows Used For Investing Activities . . . . .    (80,722)      (86,608)
                                                                ---------     ---------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . . .     74,787       148,751
  Change in Short-term Debt (net). . . . . . . . . . . . . . .     22,195        38,750
  Change in Advances to Affiliates (net) . . . . . . . . . . .    (12,857)         -
  Retirement of Cumulative Preferred Stock . . . . . . . . . .       (210)         (149)
  Retirement of Long-term Debt . . . . . . . . . . . . . . . .   (131,202)      (77,236)
  Dividends Paid on Common Stock . . . . . . . . . . . . . . .    (63,306)      (60,696)
  Dividends Paid on Cumulative Preferred Stock . . . . . . . .     (1,053)       (1,134)
                                                                ---------     ---------
        Net Cash Flows From (Used For) Financing Activities. .   (111,646)       48,286
                                                                ---------     ---------

Net Increase (Decrease) in Cash and Cash Equivalents . . . . .    (62,805)       22,326
Cash and Cash Equivalents at Beginning of Period . . . . . . .     64,828         7,755
                                                                ---------     ---------
Cash and Cash Equivalents at End of Period . . . . . . . . . .  $   2,023     $  30,081
                                                                =========     =========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $61,828,000  and
  $61,693,000  and for income taxes was  $21,198,000 and $18,062,000 in 2000 and
  1999, respectively.  Noncash acquisitions under capital leases were $7,451,000
  and $8,845,000 in 2000 and 1999, respectively.

See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                  JUNE 30, 2000

                                   (UNAUDITED)

         1.    GENERAL

                 The accompanying  unaudited  consolidated  financial statements
         should  be  read  in  conjunction   with  the  1999  Annual  Report  as
         incorporated  in and filed  with the Form  10-K.  Certain  prior-period
         amounts   have  been   reclassified   to  conform   to   current-period
         presentation.  In the opinion of management,  the financial  statements
         reflect all adjustments  (consisting of only normal recurring accruals)
         which  are  necessary  for  a  fair  presentation  of  the  results  of
         operations for interim periods.

         2.  FINANCING ACTIVITIES
             --------------------

                 In May 2000 the Company  issued $75  million of  floating  rate
         senior  unsecured notes due 2001.  During the first six months of 2000,
         the Company  reacquired  the following  first  mortgage  bonds for $101
         million.

                                                      Principal
                                                      Amount

                 % Rate        Due Date               Reacquired
                 ------        --------               ----------
                                                    (in thousands)
                 6.35          March 1, 2000          $48,000
                 6.71          June 1, 2000            48,000
                 7.125         May 1, 2024              5,000

                      In  January  2000 the  Company  redeemed  $30  million  of
         pollution  control  revenue  bonds  early with a due date of 2014.  The
         Company  has in the past,  and may in the future,  acquire  outstanding
         debt and preferred stock securities in open market transactions.

3.       RATE MATTERS

               As  discussed  in Note 4 of the Notes to  Consolidated  Financial
         Statements of the 1999 Annual Report,  the AEP System companies filed a
         settlement  agreement  with the Federal  Energy  Regulatory  Commission
         (FERC) for their  approval to  establish  an open  access  transmission
         tariff.  The Company  made a provision  in 1999 for a refund  including
         interest for amounts paid in excess of the agreed to rate.

               On March 16, 2000,  the FERC  approved the  settlement  agreement
         filed in December 1999  resolving  the issues on rehearing  raised in a
         July 30, 1999 order. Under terms of the settlement,  AEP is required to
         make refunds  retroactive  to  September  7, 1993 to certain  customers
         affected by the July 30,  1999 FERC order.  Pursuant to FERC orders the
         refunds  were  made in two  payments.  The  first  payment  was made in
         February  2000 and the second  payment  was made on August 1, 2000.  In
         addition, a new lower rate of $1.55 kw/month was made effective January
         1, 2000,  for all  transmission  service  customers and a rate of $1.42
         kw/month was established and took effect on June 16, 2000 in connection
         with the consummation of the AEP and Central and South West Corporation
         merger.  Prior to January 1, 2000, the rate was $2.04 kw/month.  Unless
         the  Company  and  the  market  grow  the  volume  of  physical   power
         transactions   to  increase  the   utilization   of  the  AEP  System's
         transmission   lines,  the  new  open  access  transmission  rate  will
         adversely impact future results of operations and cash flows.

         West Virginia

                 As discussed in Note 4 of the Notes to  Consolidated  Financial
         Statements of the 1999 Annual Report,  the Company has been involved in
         a rate  proceeding  regarding  base and expanded net energy cost (ENEC)
         rates.  On  February  7, 2000,  the  Company  and other  parties to the
         proceeding  filed a Joint  Stipulation  and  Agreement  for  Settlement
         (Joint Stipulation) with the Public Service Commission of West Virginia
         (WVPSC) for approval.

                 The Joint  Stipulation's  main provisions  include no change in
         either base or ENEC rates effective January 1, 2000 from those base and
         ENEC rates in effect  from  November  1, 1996 until  December  31, 1999
         (these rates  provide for recovery of regulatory  assets  including any
         generation  related  regulatory  assets through frozen transition rates
         and a  wires  charge  of  0.5  mills  per  kwh  provided  for in the WV
         Restructuring Plan, see Note 4); the suspension of annual ENEC recovery
         proceedings  and  deferral   accounting  for  over  or  under  recovery
         effective  January  1,  2000;  and  the  retention,   as  a  regulatory
         liability,  on the books of the net  cumulative  deferred ENEC recovery
         balance  of $66  million.  The  Joint  Stipulation  provides  that when
         deregulation  of generation  occurs in West Virginia  (WV), the Company
         will   use   this    retained    regulatory    liability    to   reduce
         generation-related  regulatory assets and, to the extent possible,  any
         additional costs or obligations that deregulation may impose.

                 Also under the Joint Stipulation the Company's share of any net
         savings from the merger  between the Company and Central and South West
         Corporation  prior  to  December  31,  2004  shall be  retained  by the
         Company.  All costs  incurred in the merger that were  allocated to the
         Company  shall be fully  charged to expense as of December 31, 2004 and
         shall not be included in any WV rate proceeding  after that date. After
         December 31, 2004, any distribution  savings related to the merger will
         be reflected in rates in any future rate proceeding before the WVPSC to
         establish  distribution  rates  or  to  adjust  rate  caps  during  the
         transition  to market  based rates.  When  deregulation  of  generation
         occurs in WV, the net retained  generation related merger savings shall
         be used to recover any generation  related  regulatory  assets that are
         not recovered under the other  provisions of the Joint  Stipulation and
         the mechanisms  provided in the  deregulation  legislation  and, to the
         extent  possible,  to recover any additional  costs or obligations that
         deregulation  may  impose.  Regardless  of whether  the net  cumulative
         deferred  ENEC  recovery   balance  and  the  net  merger  savings  are
         sufficient to offset all of the Company's generation-related regulatory
         assets,  under  the  terms of the Joint  Stipulation  there  will be no
         further  explicit  adjustment  to the  Company's  rates to provide  for
         recovery  of  generation-related  regulatory  assets  beyond  the above
         discussed  specific  adjustments  provided in the Joint Stipulation and
         the 0.5 mills per  kilowatthour  (kwh) wires charge  provided in the WV
         Restructuring  Plan  (see  Note 4 for  discussion  of WV  Restructuring
         Plan).  On June 2, 2000, the WVPSC issued an order  approving the Joint
         Stipulation.


<PAGE>


4.   INDUSTRY RESTRUCTURING
     ----------------------

                 Restructuring  legislation  has  been  enacted  in  both of the
         Company's  retail  jurisdictions  that results in the  transition  from
         cost-based  regulation for generation to customer choice market pricing
         for  the  supply  of  electricity.   The  enactment  of   restructuring
         legislation  and the ability to  determine  transition  rates and wires
         charges under restructuring  legislation resulted in the discontinuance
         of the  application  of  Statement of  Financial  Accounting  Standards
         (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation."
         Prior  to  restructuring,  the  Company  accounted  for its  operations
         according to the cost-based  regulatory  accounting  principles of SFAS
         71. Under the provisions of SFAS 71,  regulatory  assets and regulatory
         liabilities are recorded to reflect the economic  effects of regulation
         and to match expenses with regulated  revenues.  The  discontinuance of
         the  application  of SFAS 71 is based on SFAS 101  "Accounting  for the
         Discontinuance  of  Application  of  Statement  71".  Pursuant to those
         requirements and further guidance provided in the Financial  Accounting
         Standards  Board's  Emerging  Issues Task Force  (EITF)  Issue 97-4,  a
         company is  required to  write-off  regulatory  assets and  liabilities
         related to its deregulated operations,  unless recovery of such amounts
         is provided through rates to be collected in a portion of the company's
         operations   which   continues  to  be   cost-based   rate   regulated.
         Additionally,  a company  experiencing a  discontinuance  of cost-based
         rate  regulation  is  required  to  determine  if any plant  assets are
         impaired under SFAS 121,  "Accounting  for the Impairment of Long-Lived
         Assets  and  for  Long-Lived  Assets  to be  Disposed  of." A SFAS  121
         accounting    impairment    analysis    involves    estimating   future
         non-discounted  net cash flows arising from the use of an asset. If the
         undiscounted  net cash  flows  exceed  the net book value of the asset,
         then there is no impairment of the asset for accounting purposes.

                 As legislative and regulatory  proceedings  evolve, the Company
         is applying the standards  discussed  above.  Following is a summary of
         restructuring legislation,  the status of the transition and the status
         of the Company's accounting to comply with the changes.

         Virginia Restructuring

                 Under a 1999 Virginia  restructuring law a transition to choice
         of supplier for retail  customers  will commence on January 1, 2002 and
         be completed,  subject to a finding by the Virginia  State  Corporation
         Commission  (Virginia SCC) that an effective  competitive market exists
         by January 1, 2004 but not later than January 1, 2005.

                 The  Virginia  restructuring  law provides an  opportunity  for
         recovery of just and reasonable net stranded  generation-related costs.
         The  mechanisms  in the Virginia law for stranded  cost recovery are: a
         capping of incumbent utility  transition rates until as late as July 1,
         2007,  and the  application  of a wires charge upon  customers  who may
         depart the incumbent utility in favor of an alternative  supplier prior
         to  the  termination  of  the  rate  cap.  The  law  provides  for  the
         establishment   of  capped   rates   prior  to   January  1,  2001  and
         establishment  of a wires charge by the fourth  quarter of 2001.  Since
         the  Company  does not intend to request new rates,  its current  rates
         will become the capped rates.

         West Virginia Restructuring Plan

                 As discussed in Note 3 of the Notes to  Consolidated  Financial
         Statements  in the 1999  Annual  Report,  the WVPSC  issued an order on
         January 28, 2000 approving an electricity  restructuring plan. On March
         11, 2000, the West Virginia legislature approved the restructuring plan
         by joint  resolution.  The  joint  resolution  provides  that the WVPSC
         cannot implement the plan until the legislature makes necessary tax law
         changes to preserve the revenues of the state and local governments.

                 The provisions of the  restructuring  plan provide for customer
         choice to begin on January 1, 2001, or at a later date set by the WVPSC
         after  all  necessary  rules  are  in  place  (the  "starting   date");
         deregulation  of  generation  assets  occurring on the  starting  date;
         functional separation of the generation,  transmission and distribution
         businesses on the starting date and their legal corporate or structural
         separation no later than January 1, 2005; a transition  period of up to
         13 years,  during which the  incumbent  utility  must  provide  default
         service for customers who do not change suppliers unless an alternative
         default supplier is selected through a WVPSC-sponsored bidding process;
         capped and fixed rates for the 13-year  transition  period as discussed
         below;  deregulation of metering and billing; a 0.5 mills per kwh wires
         charge  applicable to all retail  customers  for the period  January 1,
         2001 through  December 31, 2010 intended to provide for recovery of any
         stranded costs including net regulatory  assets;  and  establishment by
         the Company of a rate stabilization  deferral balance of $76 million by
         the end of year ten of the  transition  period to be used as determined
         by the  WVPSC to  offset  market  prices  paid for  electricity  in the
         eleventh,  twelfth,  and thirteenth  year of the  transition  period by
         residential  and  small  commercial  customers  that do not  choose  an
         alternative supplier.

                 Default rates for  residential and small  commercial  customers
         are capped for four years after the starting  date and then increase as
         specified in the plan for the next six years.  In years eleven,  twelve
         and  thirteen of the  transition  period,  the power  supply rate shall
         equal  the  market  price  of  comparable  power.   Default  rates  for
         industrial and large commercial customers are discounted by 1% for four
         and a half  years,  beginning  July 1,  2000,  and  then  increased  at
         pre-defined  levels for the next three  years.  After  seven  years the
         power supply rate for industrial and large commercial customers will be
         market based. The Company's Joint Stipulation  agreement,  discussed in
         Note 3 above,  which  was  approved  by the  WVPSC  on June 2,  2000 in
         connection with a base rate filing, also provides additional mechanisms
         to recover the Company's regulatory assets.

         Application of SFAS 71 Discontinued

               In June 2000 the Company  discontinued the application of SFAS 71
         for the Virginia and West Virginia  retail  jurisdictional  portions of
         its generation  business since generation is no longer considered to be
         cost-based regulated in those jurisdictions and the Company was able to
         determine its transition rates and wires charges. The discontinuance in
         the West  Virginia  jurisdiction  was possible as a result of a June 2,
         2000 approval of the Joint Stipulation which established  rates,  wires
         charges and regulatory asset recovery  procedures during the transition
         period to market rates (See discussion in Note 3). The Company was also
         able to discontinue  application of SFAS 71 for the generation  portion
         of its Virginia retail  jurisdiction  after management  decided that it
         would not request capped rates  different  from its current rates.  The
         existence of effective  restructuring  legislation  in Virginia and the
         probability that the West Virginia  legislation  would become effective
         with the passage of the  required  tax  legislation  in 2001  supported
         management's decision to discontinue SFAS 71 regulatory accounting.

         The   discontinuance   of  SFAS  71  for  generation   resulted  in  an
         extraordinary gain of $9 million because  management  believes that all
         net  regulatory  assets  related  to the  Virginia  and  West  Virginia
         generating  business  will be recovered.  Under the  provisions of EITF
         97-4,  the  Company's  generation-related  net  regulatory  assets were
         transferred  to  the  transmission  and  distribution  portion  of  the
         business and will be amortized as they are recovered through charges to
         customers. An accounting impairment analysis of generation assets under
         SFAS 121 was  performed  which  concluded  there was no  impairment  of
         generation assets.

5.       CONTINGENCIES

         Litigation

               As  discussed  in Note 5 of the Notes to  Consolidated  Financial
         Statements  in the 1999 Annual  Report,  the  deductibility  of certain
         interest  deductions  related to AEP's  corporate  owned life insurance
         (COLI)  program for taxable  years 1991 through 1996 is under review by
         the Internal  Revenue Service (IRS).  Adjustments  have been or will be
         proposed  by  the  IRS   disallowing   COLI  interest   deductions.   A
         disallowance  of the COLI  interest  deductions  through  June 30, 2000
         would  reduce  earnings  by   approximately   $79  million   (including
         interest).

         The Company made  payments of taxes and interest  attributable  to COLI
         interest  deductions  for taxable  years 1991 through 1998 to avoid the
         potential  assessment  by the IRS of any  additional  above market rate
         interest on the contested amount.  The payments to the IRS are included
         on the  consolidated  balance sheet in other  property and  investments
         pending the  resolution of this matter.  The Company is seeking  refund
         through litigation of all amounts paid plus interest.

         In order to resolve  this  issue,  the Company  filed suit  against the
         United States in the U.S.  District Court for the Southern  District of
         Ohio in 1998. In 1999 a U.S. Tax Court judge decided in the  Winn-Dixie
         Stores v. Commissioner  case that a corporate  taxpayer's COLI interest
         deduction  should  be  disallowed.   Notwithstanding  the  Tax  Court's
         decision  in  Winn-Dixie,  management  has  made no  provision  for any
         possible  adverse earnings impact from this matter because it believes,
         and has been  advised by  outside  counsel,  that it has a  meritorious
         position  and will  vigorously  pursue  its  lawsuit.  In the event the
         resolution  of this  matter is  unfavorable,  it will  have a  material
         adverse  impact on  results  of  operations,  cash  flows and  possibly
         financial condition.

         Federal EPA Complaint and Notice of Violation

         As  discussed  in  Note  5  of  the  Notes  to  Consolidated  Financial
         Statements in the 1999 Annual Report,  the Company has been involved in
         litigation regarding  generating plant emissions.  Notices of Violation
         were  issued  and a  complaint  was  filed  by the  U.S.  Environmental
         Protection Agency (Federal EPA) in the U.S. District Court that alleges
         the Company,  certain affiliates and eleven unaffiliated utilities made
         modifications  to  generating  units at  certain  of  their  coal-fired
         generating plants over the course of the past 25 years that extend unit
         operating  lives  or  increase  unit  generating   capacity  without  a
         preconstruction permit in violation of the Clean Air Act. The complaint
         was amended in March 2000 to add  allegations  for  certain  generating
         units previously  named in the complaint and to include  additional AEP
         System  generating  units  previously  named  only  in the  Notices  of
         Violation  in the  complaint.  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.

         A number of  northeastern  and  eastern  states were  granted  leave to
         intervene  in the Federal  EPA's action  against the Company  under the
         Clean Air Act. A lawsuit  against  power  plants  owned by the  Company
         alleging  similar  violations to those in the Federal EPA complaint and
         Notices of Violation was filed by a number of special  interest  groups
         and has been consolidated with the Federal EPA action.

         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). Civil penalties, if ultimately imposed by the court, and the
         cost of any  required new  pollution  control  equipment,  if the court
         accepts Federal EPA's contentions, could be substantial.

         On May 10, 2000,  the Company  filed motions to dismiss all or portions
         of the complaints. Briefing on these motions was completed on August 2,
         2000.  Management  believes  its  maintenance,  repair and  replacement
         activities  were in  conformity  with the Clean Air Act and  intends to
         vigorously pursue its defense of this matter.

         In the event the Company  does 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,  stranded cost wires
         charges and future market prices for energy.


<PAGE>


         NOx Reductions

         As  discussed  in  Note  6  of  the  Notes  to  Consolidated  Financial
         Statements  in the 1999 Annual  Report,  Federal EPA had issued a final
         rule (the NOx rule) that  requires  substantial  reductions in nitrogen
         oxide (NOx) emissions in 22 eastern states, including certain states in
         which the AEP  System's  generating  plants  are  located.  A number of
         utilities,  including certain AEP System companies, had filed petitions
         seeking a review of the final rule in the U.S. Court of Appeals for the
         District of Columbia Circuit (Appeals Court).  In May 1999, the Appeals
         Court  indefinitely  stayed the requirement that states develop revised
         air quality programs to impose the NOx reductions but did not, however,
         stay the  final  compliance  date of May 1,  2003.  In  March  2000 the
         Appeals  Court issued a decision  generally  upholding the NOx rule. On
         April 20,  2000,  certain AEP System  companies  and other  petitioners
         filed for  rehearing  of this  decision  including a  rehearing  by the
         entire  Appeals  Court.  On June 22, 2000, the Appeals Court denied the
         petition  for  rehearing  and  lifted the stay  related to the  states'
         development  of  revised  air  quality   programs  to  impose  the  NOx
         reductions.  The  petition  for a rehearing  before the entire  Appeals
         Court was also denied. The AEP System companies subject to the NOx rule
         plan to appeal to the U.S. Supreme Court.

         Preliminary  estimates indicate that compliance with NOx rule upheld by
         the Appeals  Court could  result in required  capital  expenditures  of
         approximately  $365 million for the  Company.  Since  compliance  costs
         cannot be estimated with certainty, the actual costs to comply could be
         significantly   different  than  the  Company's   preliminary  estimate
         depending  upon  the  compliance   alternatives   selected  to  achieve
         reductions  in NOx  emissions.  Unless  such costs are  recovered  from
         customers through regulated rates, wires charges or future market price
         of  electricity,  they will have a  material  adverse  effect on future
         results of operations, cash flows and possibly financial condition.

         Other

         The Company continues to be involved in certain other matters discussed
in its 1999 Annual Report.


<PAGE>





                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES

          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                             AND FINANCIAL CONDITION

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
                     ---------------------------------------
RESULTS OF OPERATIONS

        Net income increased $28 million or 255% for the quarter and $36 million
or 73% for  the  year-to-date  period  due to  increased  operating  income,  an
increase in  nonoperating  income from  electricity  trading  gains  outside the
Company's  traditional  marketing  area  and  an  extraordinary  gain  from  the
discontinuance of regulatory accounting.

        Income statement line items which changed significantly were:

                                     Increase (Decrease)

                             Second Quarter       Year-to-Date

                            (in millions)  %   (in millions)   %

Operating Revenues . . . . .     $56      15       $ 84       10
Fuel Expense . . . . . . . .      (7)     (7)       (32)     (14)
Purchased Power Expense. . .      45      74         87       78
Maintenance Expense. . . . .      (9)    (24)       (10)     (14)
Federal Income Taxes . . . .      10     248         14       51
Nonoperating Income. . . . .       3     N.M.         5      N.M.
Extraordinary Gain . . . . .       9     N.M.         9      N.M.

N.M. = Not Meaningful

        The increase in operating  revenues and purchased power expense resulted
from the Company's share of increased wholesale electricity  transactions by the
American  Electric  Power System  Power Pool (AEP Power Pool).  The Company as a
member of the AEP Power Pool  shares in the  revenues  and cost of the AEP Power
Pool's  wholesale  sales and forward trades to neighboring  utility  systems and
power  marketers.  As a result of an  affiliate's  major  industrial  customer's
decision  not to  continue  a purchase  power  agreement,  additional  power was
delivered  to the AEP Power Pool.  The  Company's  share of these AEP Power Pool
marketing and trading transactions within the AEP System's traditional marketing
area (within two  transmission  systems of AEP System) are recorded as operating
revenues and  purchases.  Forward  trading sales and purchases are recorded on a
net basis in operating revenues.


<PAGE>


        Fuel expense decreased due to discontinuance of deferred  accounting for
over or under recovery of fuel cost  effective  January 1, 2000 as a result of a
Joint  Stipulation  and Agreement for Settlement  approved by the Public Service
Commission of West Virginia (WVPSC).

        The decrease in maintenance expense is due to the effect of boiler plant
        maintenance  repairs to the Amos Plant during 1999. Federal income taxes
        attributable  to  operations  increased  primarily due to an increase in
        pre-tax  operating  income.  Nonoperating  income  increased  due  to an
        increase in net gains from the  non-regulated  electric  trading outside
        the AEP Power

Pool's  traditional  marketing  area.  The AEP Power Pool enters into  financial
transactions  for the  purchase  and sale of  electricity  options,  futures and
swaps, and for the forward  purchase and sale of electricity  outside of the AEP
System's traditional  marketing area. The Company's share of these non-regulated
and financial trading activities are included in nonoperating income.

        The  extraordinary  gain  in the  second  quarter  was a  result  of the
discontinuance  of  Statement  of  Financial  Accounting  Standards  (SFAS)  71,
"Accounting for the Effects of Certain Types of Regulation,"  for the generation
portion of the  Company's  business in Virginia and West Virginia as a result of
restructuring  legislation in both states. Based on management's belief that all
net  regulatory  assets  related to the  Virginia and West  Virginia  generation
business will be  recovered,  the Company's  generation-related  net  regulatory
assets were  transferred to the  transmission  and  distribution  portion of the
business  and  will be  amortized  as they  are  recovered  through  charges  to
customers. The Company performed an accounting impairment analysis of generation
assets under SFAS 121  "Accounting  for the Impairment of Long-lived  Assets and
for Long-lived  Assets to Be Disposed Of" and concluded  there was no accounting
impairment of generation assets.

FINANCIAL CONDITION

        Total plant and  property  additions  including  capital  leases for the
first six months of 2000 were $88  million.  Short-term  debt  increased  by $22
million since December 1999. The Company has in the past, and may in the future,
acquire   outstanding  debt  and  preferred  stock  securities  in  open  market
transactions.


<PAGE>


        In January  2000 the  Company  redeemed  $30  million of 7.40  pollution
control bonds due 2014 at 102%.  In March 2000 the Company  redeemed at maturity
$48 million of 6.35% first mortgage  bonds.  In June 2000 the Company issued $75
million of senior unsecured medium term notes with a variable  interest rate due
in 2001. Also in June 2000 the Company redeemed at maturity $48 million of 6.71%
first mortgage bonds.

OTHER MATTERS

Litigation

        As discussed in Note 5 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report,  the  deductibility  of certain  interest  deductions
related to AEP?s corporate owned life insurance (COLI) program for taxable years
1991  through  1996 is under  review  by the  Internal  Revenue  Service  (IRS).
Adjustments  have been or will be proposed by the IRS disallowing  COLI interest
deductions. A disallowance of the COLI interest deductions through June 30, 2000
would reduce earnings by approximately $79 million (including interest).

        The Company  made  payments of taxes and interest  attributable  to COLI
interest  deductions  for taxable years 1991 through 1998 to avoid the potential
assessment  by the IRS of any  additional  above  market  rate  interest  on the
contested  amount.  The  payments to the IRS are  included  on the  consolidated
balance sheet in other property and  investments  pending the resolution of this
matter.  The Company is seeking  refund  through  litigation of all amounts paid
plus interest.

        In order to resolve  this  issue,  the  Company  filed suit  against the
United States in the U.S.  District  Court for the Southern  District of Ohio in
1998.  In 1999 a U.S.  Tax  Court  judge  decided  in the  Winn-Dixie  Stores v.
Commissioner case that a corporate  taxpayer's COLI interest deduction should be
disallowed.  Notwithstanding the Tax Court?s decision in Winn-Dixie,  management
has made no provision for any possible  adverse earnings impact from this matter
because it  believes,  and has been  advised by outside  counsel,  that it has a
meritorious  position and will vigorously  pursue its lawsuit.  In the event the
resolution of this matter is unfavorable, it will have a material adverse impact
on results of operations, cash flows and possibly financial condition.


<PAGE>


Application of SFAS 71 Discontinued

        In June 2000 the Company discontinued the application of SFAS 71 for the
Virginia and West  Virginia  retail  jurisdictional  portions of its  generation
business since generation is no longer considered to be cost-based  regulated in
those  jurisdictions  and the Company was able to determine its transition rates
and wires charges.  The  discontinuance  in the West Virginia  jurisdiction  was
possible as a result of a June 2, 2000 approval of the Joint  Stipulation  which
established rates, wires charges and regulatory asset recovery procedures during
the  transition  period to market rates (See  discussion in Note 3). The Company
was also able to discontinue  application of SFAS 71 for the generation  portion
of its Virginia retail  jurisdiction  after management decided that it would not
request  capped  rates  different  from its  current  rates.  The  existence  of
effective  restructuring  legislation in Virginia and the  probability  that the
West  Virginia  legislation  would  become  effective  with the  passage  of the
required tax legislation in 2001 supported  management's decision to discontinue
SFAS 71 regulatory accounting.

        The   discontinuance   of  SFAS  71  for   generation   resulted  in  an
extraordinary  gain of $9  million  because  management  believes  that  all net
regulatory assets related to the Virginia and West Virginia  generating business
will be  recovered.  Under the  provisions  of  Financial  Accounting  Standards
Board's   Emerging   Issues  Task  Force  (EITF)  Issue  97-4,   the   Company's
generation-related  net regulatory  assets were  transferred to the transmission
and  distribution  portion of the  business  and will be  amortized  as they are
recovered  through charges to customers.  An accounting  impairment  analysis of
generation  assets under SFAS 121 was  performed  which  concluded  there was no
impairment of generation assets.

Federal EPA Complaint and Notice of Violation

        As discussed in Note 5 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, the Company has been involved in litigation regarding
generating plant emissions. Notices of Violation were issued and a complaint was
filed by the U.S.  Environmental  Protection  Agency  (Federal  EPA) in the U.S.
District  Court  that  alleges  the  Company,   certain  affiliates  and  eleven
unaffiliated  utilities  made  modifications  to generating  units at certain of
their  coal-fired  generating  plants  over the course of the past 25 years that
extend unit  operating  lives or increase  unit  generating  capacity  without a
preconstruction  permit in  violation of the Clean Air Act.  The  complaint  was
amended in March 2000 to add allegations for certain generating units previously
named in the complaint and to include  additional  AEP System  generating  units
previously  named only in the Notices of Violation in the  complaint.  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.

        A number of  northeastern  and  eastern  states  were  granted  leave to
intervene in the Federal  EPA's action  against the Company  under the Clean Air
Act. A lawsuit  against  power  plants  owned by the  Company  alleging  similar
violations  to those in the Federal EPA  complaint  and Notices of Violation was
filed by a number of special interest groups and has been  consolidated with the
Federal EPA action.

        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). Civil penalties,  if ultimately imposed by the court, and the cost of any
required new pollution  control  equipment,  if the court accepts  Federal EPA's
contentions, could be substantial.

        On May 10, 2000, the Company filed motions to dismiss all or portions of
the  complaints.  Briefing  on these  motions was  completed  on August 2, 2000.
Management believes its maintenance,  repair and replacement  activities were in
conformity  with the Clean Air Act and intends to vigorously  pursue its defense
of this matter.

        In the event the Company  does 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,  stranded cost wires charges and future market prices
for energy. NOx Reductions

        As discussed in Note 6 of the Notes to Consolidated Financial Statements
in the 1999  Annual  Report,  Federal EPA had issued a final rule (the NOx rule)
that requires  substantial  reductions in nitrogen  oxide (NOx)  emissions in 22
eastern states,  including  certain states in which the AEP System's  generating
plants  are  located.  A number  of  utilities,  including  certain  AEP  System
companies,  had filed  petitions  seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit  (Appeals  Court).  In May
1999, the Appeals Court indefinitely  stayed the requirement that states develop
revised air quality programs to impose the NOx reductions but did not,  however,
stay the final  compliance  date of May 1, 2003. In March 2000 the Appeals Court
issued a decision  generally  upholding the NOx rule. On April 20, 2000, certain
AEP System companies and other  petitioners filed for rehearing of this decision
including a rehearing by the entire Appeals Court. On June 22, 2000, the Appeals
Court  denied the  petition  for  rehearing  and lifted the stay  related to the
states'   development  of  revised  air  quality  programs  to  impose  the  NOx
reductions.  The petition for a rehearing  before the entire  Appeals  Court was
also denied.  The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.

        Preliminary  estimates  indicate that compliance with NOx rule upheld by
the Appeals Court could result in required capital expenditures of approximately
$365 million for the Company.  Since  compliance  costs cannot be estimated with
certainty,  the actual costs to comply could be significantly different than the
Company's  preliminary  estimate  depending  upon  the  compliance  alternatives
selected to achieve reductions in NOx emissions. Unless such costs are recovered
from customers through regulated rates,  wires charges or future market price of
electricity,  they will have a  material  adverse  effect on future  results  of
operations, cash flows and possibly financial condition.

Market Risks

        The Company has certain market risks inherent in its business activities
from changes in electricity  commodity  prices and interest  rates.  Market risk
represents  the risk of loss that may impact the Company due to adverse  changes
in commodity market prices and interest rates. The Company's  exposure to market
risk  from  the  trading  of  electricity  and  related   financial   derivative
instruments,  which are allocated to the Company  through the American  Electric
Power  System  Power  Pool,  were less than $8 million  at June 30,  2000 and $4
million at December 31, 1999 based on the use of a risk measurement  model which
calculates  Value at Risk (VaR).  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 three-day holding period.

        The exposure to changes in interest rates from the Company's  short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.


<PAGE>
<TABLE>
<CAPTION>


                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           -------------------    --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)

<S>                                        <C>        <C>          <C>        <C>
OPERATING REVENUES . . . . . . . . . . .   $437,911   $383,783     $754,239   $666,060
                                           --------   --------     --------   --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    140,841    106,397      230,238    174,312
  Purchased Power. . . . . . . . . . . .     34,936     16,247       55,356     29,394
  Other Operation. . . . . . . . . . . .     54,307     66,255      129,609    128,894
  Maintenance. . . . . . . . . . . . . .     15,474     19,956       31,896     35,183
  Depreciation and Amortization. . . . .     40,887     43,257       95,085     86,370
  Taxes Other Than Federal Income Taxes.     19,922     22,971       37,456     46,296
  Federal Income Taxes . . . . . . . . .     35,827     29,021       40,232     39,841
                                           --------   --------    ---------   --------

          TOTAL OPERATING EXPENSES . . .    342,194    304,104      619,872    540,290
                                           --------   --------    ---------   --------

OPERATING INCOME . . . . . . . . . . . .     95,717     79,679      134,367    125,770

NONOPERATING INCOME. . . . . . . . . . .      1,815      1,199        2,362      2,147
                                           --------   --------    ---------   --------

INCOME BEFORE INTEREST CHARGES . . . . .     97,532     80,878      136,729    127,917

INTEREST CHARGES . . . . . . . . . . . .     29,979     29,854       61,037     59,873
                                           --------   --------     --------   --------

NET INCOME . . . . . . . . . . . . . . .     67,553     51,024       75,692     68,044

PREFERRED STOCK DIVIDEND REQUIREMENTS. .         61      1,735          121      3,547
                                           --------   --------     --------   --------

EARNINGS APPLICABLE TO COMMON STOCK. . .   $ 67,492   $ 49,289     $ 75,571   $ 64,497
                                           ========   ========     ========   ========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           ------------------     --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD
  AS PREVIOUSLY REPORTED . . . . . . .    $733,957  $717,767      $764,225    $739,031
CONFORMING CHANGE IN ACCOUNTING POLICY      (5,984)   (5,172)       (5,331)     (4,644)
                                          --------  --------      --------    --------
ADJUSTED BALANCE AT BEGINNING OF
  PERIOD . . . . . . . . . . . . . . . .   727,973   712,595       758,894     734,387
NET INCOME . . . . . . . . . . . . . . .    67,553    51,024        75,692      68,044

DEDUCTIONS:
  Cash Dividends Declared:
        Common Stock . . . . . . . . . .    39,000    37,000        78,000      74,000
        Preferred Stock. . . . . . . . .        61     1,735           121       3,547
                                          --------  --------      --------    --------

BALANCE AT END OF PERIOD . . . . . . . .  $756,465  $724,884      $756,465    $724,884
                                          ========  ========      ========    ========

The Company is a wholly owned subsidiary of American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.

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


                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                          <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .  $3,201,217     $3,152,319
  Transmission. . . . . . . . . . . . . . . . . . . . . . .     577,345        566,629
  Distribution. . . . . . . . . . . . . . . . . . . . . . .   1,190,819      1,157,091
  General . . . . . . . . . . . . . . . . . . . . . . . . .     235,535        307,378
  Construction Work in Progress . . . . . . . . . . . . . .      80,163        101,550
  Nuclear Fuel. . . . . . . . . . . . . . . . . . . . . . .     228,013        226,927
                                                             ----------     ----------

          Total Electric Utility Plant. . . . . . . . . . .   5,513,092      5,511,894

  Accumulated Depreciation. . . . . . . . . . . . . . . . .   2,266,917      2,263,925
                                                             ----------     ----------

          Net Electric Utility Plant. . . . . . . . . . . .   3,246,175      3,247,969
                                                             ----------     ----------

OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . .      42,765         41,433
                                                             ----------     ----------

CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .       4,342          5,830
  Special Deposits for Reacquisition of Long-term Debt. . .        -            50,000
  Accounts Receivable:
    General . . . . . . . . . . . . . . . . . . . . . . . .      42,182         49,228
    Affiliate . . . . . . . . . . . . . . . . . . . . . . .      13,915         15,254
  Materials and Supplies. . . . . . . . . . . . . . . . . .      56,469         58,196
  Fuel Inventory. . . . . . . . . . . . . . . . . . . . . .      23,587         26,434
  Under-recovered Fuel Costs. . . . . . . . . . . . . . . .      54,579         30,911
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .       6,839          5,353
                                                             ----------     ----------

          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     201,913        241,206
                                                             ----------     ----------

REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .     230,707        240,059
                                                             ----------     ----------

REGULATORY ASSETS DESIGNATED FOR SECURITIZATION . . . . . .     953,249        953,219
                                                             ----------     ----------

NUCLEAR DECOMMISSIONING TRUST . . . . . . . . . . . . . . .      91,045         86,122
                                                             ----------     ----------

DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      26,985         37,812
                                                             ----------     ----------

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $4,792,839     $4,847,850
                                                             ==========     ==========

See Notes to Consolidated Financial Statements.

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


                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $25 Par Value:
    Authorized - 12,000,000 Shares

<S>                                                          <C>            <C>
    Outstanding - 6,755,535 Shares. . . . . . . . . . . . .  $  168,888     $  168,888
  Paid-in Capital . . . . . . . . . . . . . . . . . . . . .     405,000        405,000
  Retained Earnings . . . . . . . . . . . . . . . . . . . .     756,465        758,894
                                                             ----------     ----------
          TOTAL COMMON SHAREHOLDER'S EQUITY . . . . . . . .   1,330,353      1,332,782

PREFERRED STOCK . . . . . . . . . . . . . . . . . . . . . .       5,967          5,967
CPL-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED
 SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR
 SUBORDINATED DEBENTURES OF CPL . . . . . . . . . . . . . .     150,000        150,000
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . .   1,454,554      1,304,541
                                                             ----------     ----------

          TOTAL CAPITALIZATION. . . . . . . . . . . . . . .   2,940,874      2,793,290
                                                             ----------     ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .        -           150,000
  Advances from Affiliates. . . . . . . . . . . . . . . . .     253,779        322,158
  Accounts Payable - General. . . . . . . . . . . . . . . .     112,793         88,702
  Accounts Payable - Affiliated Companies . . . . . . . . .      36,038         35,344
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      23,973         41,121
  Interest Accrued. . . . . . . . . . . . . . . . . . . . .      27,631         14,723
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      33,048         25,349
                                                             ----------     ----------

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     487,262        677,397
                                                             ----------     ----------

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .   1,224,470      1,234,175
                                                             ----------     ----------

DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . .     130,703        133,306
                                                             ----------     ----------

DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . .       9,530          9,682
                                                             ----------     ----------

CONTINGENCIES (Note 6)

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $4,792,839     $4,847,850
                                                             ==========     ==========

See Notes to Consolidated Financial Statements.

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





                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                 Six Months Ended

                                                                     June 30,

                                                               2000           1999
                                                               ----           ----
                                                                  (in thousands)

OPERATING ACTIVITIES:
<S>                                                          <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 75,692       $ 68,044
  Adjustments For Non-Cash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .  101,723         95,659
    Deferred Federal Income Taxes. . . . . . . . . . . . . .   (9,255)       (12,134)
    Deferred Investment Tax Credits. . . . . . . . . . . . .   (2,603)        (2,602)
  Changes in Certain Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    8,385         (8,754)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    4,575           (714)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .   24,785         (7,966)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .  (17,148)        14,603
    Interest Accrued . . . . . . . . . . . . . . . . . . . .   12,908           (389)
    Fuel Recovery. . . . . . . . . . . . . . . . . . . . . .  (23,668)         2,780
    Other. . . . . . . . . . . . . . . . . . . . . . . . . .    9,493         (1,072)
                                                             --------       --------
        Net Cash Flows From Operating Activities . . . . . .  184,887        147,455
                                                             --------       --------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .  (85,215)       (80,142)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .   (4,067)          (581)
                                                             --------       --------
        Net Cash Flows Used For Investing Activities . . . .  (89,282)       (80,723)
                                                             --------       --------

FINANCING ACTIVITIES:
  Retirement of Long-term Debt . . . . . . . . . . . . . . . (100,000)      (125,000)
  Reacquisition of Long-term Debt. . . . . . . . . . . . . .  (50,000)          -
  Special Deposit for Reacquisition of Long-term Debt. . . .   50,000           -
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .  149,413           -
  Changes in Advances from Affiliates. . . . . . . . . . . .  (68,379)       140,337
  Dividends Paid on Common Stock . . . . . . . . . . . . . .  (78,000)       (74,000)
  Dividends Paid on Preferred Stock. . . . . . . . . . . . .     (127)        (3,923)
                                                             --------       --------
        Net Cash Flows Used For Financing Activities . . . .  (97,093)       (62,586)
                                                             --------       --------

Net Increase (Decrease) in Cash and Cash Equivalents . . . .   (1,488)         4,146
Cash and Cash Equivalents at Beginning of Period . . . . . .    5,830          5,195
                                                             --------       --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $  4,342       $  9,341
                                                             ========       ========


Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $46,981,000  and
  $51,241,000  and for income taxes was  $48,141,000 and $29,987,000 in 2000 and
  1999, respectively.

See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>


                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                  JUNE 30, 2000

                                   (UNAUDITED)

1.      GENERAL

        The accompanying  unaudited  consolidated financial statements should be
read in  conjunction  with the Company's  1999 Form 10-K.  Certain  prior-period
amounts have been reclassified to conform to current-period presentation. In the
opinion  of  management,   the  financial  statements  reflect  all  adjustments
(consisting of only normal  recurring  accruals)  which are necessary for a fair
presentation of the results of operations for interim periods.

2.       MERGER

         In June 2000 the merger of American Electric Power Company,  Inc. (AEP)
and  Central and South West  Corporation  (CSW),  the parent  company of Central
Power and Light  Company,  was completed.  As part of the change in control,  an
adjustment  to conform the Company's  accounting  for vacation pay accruals with
AEP's accounting policy was necessary.

         The effect of the  conforming  change in  accounting  was to reduce net
assets by $5.3  million  at  December  31,  1999 and  reduce  net income by $0.7
million for the three  months  ended March 31, 2000 and by $0.4 million and $0.9
million for the three months and six months ended June 30, 1999, respectively.

         In  connection  with  the  merger,  the  Texas  Commission  approved  a
settlement  agreement that provides for, among other things,  sharing net merger
savings with customers over six years after  consummation  of the merger through
rate reduction riders. In the event that actual net merger savings are less than
the  rate  reduction  riders,  results  of  operations  and cash  flows  will be
adversely affected.

3.       TEXAS RESTRUCTURING

    In June 1999  restructuring  legislation  was signed  into law in Texas that
will restructure the electric utility  industry (Texas  Legislation).  The Texas
Legislation, among other things:

o gives  customers of  investor-owned  utilities the opportunity to choose their
electric  provider  beginning  January 1, 2002;

o provides for the recovery of  regulatory  assets and of other  stranded  costs
through securitization and non-bypassable wires charges;

o        requires reductions in nitrogen oxide and sulfur dioxide emissions;

o    provides  a rate  freeze  until  January  1,  2002  followed  by a 6%  rate
     reduction for residential  and small  commercial  customers,  an additional
     rate  reduction  for   low-income   customers  and  a  number  of  customer
     protections;

o sets an earnings test for the three years of rate freeze (1999 through  2001);
o sets  certain  limits for  ownership  and  control of  generation  capacity by
companies; and

o    requires a filing after January 10, 2004 to finalize  stranded  costs (2004
     true-up  proceeding)  including  final fuel recovery  balances,  regulatory
     assets, certain environmental costs,  accumulated excess earnings and other
     issues.

     Delivery of electricity will continue to be the responsibility of the local
electric transmission and distribution utility company at regulated prices. Each
electric  utility must submit a plan to unbundle its business  activities into a
retail electric  provider,  a power  generation  company and a transmission  and
distribution utility.

     The Company and its affiliated  electric  utilities  which operate in Texas
filed  their  business  separation  (unbundling)  plan with the  Public  Utility
Commission  of Texas  (Texas  Commission)  on  January  10,  2000.  The  filings
described a financial and  accounting  functional  separation but not a legal or
structural separation, described how operations will be physically separated and
the functions they will perform,  described  competitive  energy  services,  and
provided a code of conduct.  In March 2000, the Texas  Commission ruled that the
plan was not in compliance with the Texas  Legislation and ordered revised plans
be submitted  to separate the  generation  business  from the wires  business in
separate  legal  entities by January 1, 2002.  In May 2000 a revised  separation
plan was  filed,  which  the  Texas  Commission  approved  on July 7, 2000 in an
interim order.

     Under the Texas  Legislation,  electric  utilities  are  allowed,  with the
approval  of  the  Texas   Commission,   to  recover  stranded  costs  including
generation-related  regulatory  assets that may not be  recoverable  in a future
competitive market. The approved costs can be refinanced through securitization,
which is a  financing  structure  designed  to  provide  state  sponsored  lower
financing  costs  than  are  available  through   conventional   public  utility
financings.  The securitized  amounts plus interest are then recovered through a
non-bypassable  wires charge.  In 1999 the Company filed an application with the
Texas  Commission  to  securitize  approximately  $1.27  billion  of its  retail
generation-related  regulatory  assets and  approximately  $47  million in other
qualified restructuring costs.

     On  February  10,  2000,  the  Texas  Commission   tentatively  approved  a
settlement,  which will  permit the  Company to  securitize  approximately  $764
million  of net  regulatory  assets.  The Texas  Commission's  order  authorized
issuance  of up to $797  million  of  securitization  bonds  including  the $764
million  for  recovery  of net  regulatory  assets  and $33  million  for  other
qualified  refinancing  costs.  The $764 million for recovery of net  regulatory
assets reflects the recovery of $949 million of regulatory assets offset by $185
million of customer benefits associated with accumulated  deferred income taxes.
The Company had previously proposed in its filing to flow these benefits back to
customers  over the 14-year  term of the  securitization  bonds.  The  remaining
regulatory assets originally requested by the Company in its 1999 securitization
request has been  included  in a March 2000  filing  with the Texas  Commission,
requesting  recovery of an additional $1.1 billion of stranded costs.  The March
2000 filing for $1.1 billion includes recovery of approximately  $800 million of
South Texas Project  (STP) nuclear plant costs  included in utility plant on the
Balance Sheet and  previously  identified as "Excess Cost Over Market" (ECOM) by
the Texas Commission for regulatory  purposes. A final determination on recovery
will  occur  as  part of the  2004  true-up  proceeding  and  the  total  amount
recoverable can be securitized.

     On  April  11,  2000,   four  parties   appealed  the  Texas   Commission's
securitization  order to the Travis County District Court.  One of these appeals
challenges  the  ability  to  recover  securitization  charges  under  the Texas
Constitution.  The Company  will not be able to issue the  securitization  bonds
until these appeals are resolved.  As a result, the securitization bonds are not
likely to be issued until 2001.

         The Company's  financial  statements  have  historically  reflected the
effects of applying  the  requirements  of  Statement  of  Financial  Accounting
Standards   (SFAS)  71,   "Accounting  for  the  Effects  of  Certain  Types  of
Regulation".  Pursuant to those requirements,  regulatory assets and liabilities
have been recorded to reflect the economic effect of cost-based regulation. When
a company  determines  that its operations or a segment of its operations are no
longer cost-based rate regulated, it is required to apply the provisions of SFAS
101 "Accounting for the Discontinuance of Application of Statement 71". Pursuant
to those requirements and further guidance provided in the Financial  Accounting
Standards  Board's  Emerging  Issues Task Force  (EITF)  Issue 97-4, a regulated
entity is required to write-off regulatory assets and liabilities related to the
portion of its  operations  whose rates will no longer be cost-based  regulated,
unless recovery of such amounts is provided through rates to be collected in the
portion  of  the   company's   operations   which   continue  to  be  regulated.
Additionally,  the  Company is  required to  determine  if any plant  assets are
impaired under SFAS 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of" and record any accounting impairment.

         As a result of the scheduled deregulation of generation under the Texas
Legislation,  the  application  of  SFAS 71 for the  generation  portion  of the
Company's  business in Texas was  discontinued in 1999.  Under the provisions of
EITF  97-4,  the  Company's   generation-related   net  regulatory  assets  were
transferred to the  transmission  and  distribution  portion of the business and
will be  amortized  as they are  recovered  through  charges to customers of the
regulated  distribution  business.  Since the  Company has net  stranded  costs,
management   currently  believes  that   substantially  all   generation-related
regulatory  assets should be recovered as provided by the Texas Legislation when
an electric  utility has a stranded  cost.  If future  events were to occur that
made the recovery of  regulatory  assets no longer  probable,  the Company would
write-off the portion of such assets deemed  unrecoverable  as a non-cash charge
to earnings.

     Recovery of  generation-related  regulatory  assets and stranded  costs are
subject to a final  determination  by the Texas  Commission  in 2004.  The Texas
Legislation  provides that all such finally  determined  stranded  costs will be
recovered.

         An  impairment  analysis  for  generation  assets  under  SFAS  121 was
completed  which  concluded  there was no  accounting  impairment  of generation
assets  at the  time  the  Company  discontinued  application  of  SFAS  71.  An
impairment  analysis involves  estimating future net cash flows arising from the
use of an asset. If the undiscounted net cash flows exceed the net book value of
the asset,  then there is no  impairment  of the asset to record for  accounting
purposes.  The Company will test its generation assets for impairment under SFAS
121 when circumstances change. However, on a discounted basis the cash flows are
less than the Company's  generating asset's net book value and together with the
Company's  generation-related  regulatory  assets create a recoverable  stranded
cost under the Texas Legislation.

         The Texas  Legislation  also  provides  that each year  during the 1999
through 2001 rate freeze period,  electric  utilities are subject to an earnings
test.  For electric  utilities with stranded costs any earnings in excess of the
most recently  approved cost of capital in its last rate case must be applied to
reduce stranded costs. As a result, the Company recorded a charge to earnings of
$32 million for the 1999 estimated excess earnings under the Texas  Legislation.
The Texas Commission is required under the Texas Legislation to certify that the
Company's  calculation  of excess  earnings for 1999 is correct by September 30,
2000.

         A Texas settlement  agreement in connection with the AEP and CSW merger
permits  the Company to apply for  regulatory  purposes up to $20 million of STP
ECOM Plant assets a year in 2000 and 2001 to reduce excess earnings,  if any.
For book purposes, plant assets will be depreciated on a systematic and rational
basis unless impaired. To the extent excess  earnings  exceed $20 million in
2000 or 2001 the Company will establish a regulatory liability by a charge
to earnings.

        Beginning  January  1,  2002,  fuel  costs  will not be subject to Texas
Commission fuel reconciliation proceedings.  Consequently, the Company will file
a final fuel  reconciliation with the Texas Commission which reconciles its fuel
costs through the period ending  December 31, 2001. Any final fuel balances will
be included for recovery in the 2004 true-up proceeding.


<PAGE>


     The Company  continues to analyze the impact of the Texas electric  utility
industry  restructuring  legislation  on  its  operations.  Although  management
believes that the Texas Legislation  provides for full recovery of the Company's
stranded  costs  and that the  Company  does  not have a  recordable  accounting
impairment,  a final  determination  of whether the Company will  experience any
accounting loss from an inability to recover generation-related assets and other
restructuring  related  costs in Texas  cannot  be made  until  such time as the
litigation  and the regulatory  process are complete  following the 2004 true-up
proceeding. In the event the Company is unable after the 2004 true-up proceeding
to  recover  all or a  portion  of  its  generation-related  regulatory  assets,
stranded costs and other  restructuring  related costs, it could have a material
adverse  effect on results of  operations,  cash  flows and  possibly  financial
condition.

4.       RATE MATTERS

Texas Base Rates

         In November 1995 the Company filed with the Texas  Commission a request
to increase  its retail  base rates by $71  million.  In October  1997 the Texas
Commission  issued a final order which lowered the Company's  annual retail base
rates by $19 million from the rate level which  existed  prior to May 1996.  The
Texas  Commission  also  included a "glide path" rate  methodology  in the final
order  pursuant to which annual rates were reduced by $13 million  beginning May
1, 1998 and an additional reduction of $13 million on May 1, 1999.

         The Company  appealed  the final order to the State  District  Court of
Travis County (District Court).  The primary issues being appealed include:  the
classification  of $800 million of invested capital in STP as ECOM and assigning
it a lower  return on equity  than  other  generation  property;  the use of the
"glide path" rate  reduction  methodology;  and an $18 million  disallowance  of
billings from an  affiliate,  CSW  Services.  The Company has a 25.2%  ownership
interest  in the  2,501 MW STP.  As part of the  appeal,  the  Company  sought a
temporary  injunction to prohibit the Texas  Commission  from  implementing  the
"glide path" rate reduction methodology. The temporary injunction was denied and
the "glide path" rate reduction was  implemented.  In February 1999 the District
Court  affirmed  the Texas  Commission  order in regard to the three major items
discussed above.

         The  Company  appealed  the  District  Court's  findings  to the  Third
District of Texas Court of Appeals  (Appeals  Court) which in July 2000,  issued
its opinion  upholding  the  District  Court except for the  disallowance  of an
affiliated  service  billings.  Under  Texas law,  specific  findings  regarding
affiliate  transactions must be made by the Texas Commission.  In regards to the
affiliate  expense  issue,  the findings were not complete in the opinion of the
Appeals  Court who remanded the issue back to the Texas  Commission.  Management
intends to seek a  rehearing  of the  Appeals  Court's  opinion and is unable to
predict the final  resolution of its appeal.  If the Company is  unsuccessful in
its  appeal it will  continue  to  adversely  affect  the  Company's  results of
operations, cash flows and possibly financial condition.

         As part of the AEP/CSW merger approval  process in Texas, a stipulation
agreement was approved which resulted in the withdrawal of the appeal related to
the "glide path" rate  methodology.  The Company will continue its appeal of the
ECOM classification of STP property and the disallowed affiliated billings.

Fuel Factor Filings

        In March 2000 the Texas Commission  approved a settlement related to the
Company's  January  2000 fuel factor  filing.  The  settlement  provided  for an
increase in fuel factor  revenues of $43.3 million  annually  beginning in March
2000 and a surcharge  to provide  $24.7  million for under  recovered  fuel cost
beginning in April 2000.

        In July 2000 the Company filed with the Texas  Commission an application
for  authority  to  implement  an increase in fuel  factors  effective  with the
September 2000 billing month.  The Company also proposed to implement an interim
fuel surcharge to collect its under-recovered fuel costs,  including accumulated
interest,  over a 12-month  period  beginning in October  2000.  In early August
2000, a  settlement  was reached  between the various  parties.  The  settlement
allows for an increase in fuel factor  revenues of $173.5  million  annually and
provides for a surcharge of $21.3 million for under-recovered fuel costs for the
period of December  1999  through May 2000 and a surcharge  not to exceed  $65.1
million for  projected  under-recoveries  for the period from June 2000  through
August 2000. A compliance filing detailing the actual  under-recoveries for June
2000 through August 2000 will be made in September 2000. The settlement requires
the approval of the Texas Commission.

5.       FINANCING ACTIVITIES

         In February  2000 the Company sold $150  million of unsecured  floating
rate notes.  The notes have a two-year  final maturity of February 22, 2002, but
may be redeemed at par after one year. The interest rate will reset quarterly at
the then  current  three-month  London  Inter-Bank  Overnight  Rate (LIBOR) plus
0.45%.  The initial  rate,  set February 18,  2000,  was 6.56%.  Net proceeds of
$149.4  million were used to refund $100 million of Series HH, 6% First Mortgage
Bonds maturing April 1, 2000 and to repay a portion of short-term debt.

         In March 2000 the Company  reacquired  $50 million of its 7-1/2% Series
AA First Mortgage Bonds due March 1, 2020. The reacquisition was funded from the
issuance of Series 1999B in December 1999 the proceeds of which were placed in a
special deposit for reacquisition.

        The Company has in the past, and may in the future,  acquire outstanding
debt and preferred stock securities in open market transactions.

6.      CONTINGENCIES

Municipal Franchise Fee Litigation

        The  Company  has  been  involved  in  litigation   regarding  municipal
franchise  fees in Texas as a result of a class action suit filed by the City of
San Juan,  Texas in 1996.  The City of San Juan  claims  the  Company  underpaid
municipal franchise fees and seeks damages of up to $300 million plus attorney's
fees. The Company filed a counterclaim for overpayment of franchise fees.

        During 1997, 1998 and 1999 the litigation moved procedurally through the
Texas Court System and was sent to mediation without resolution.

        In 1999 a class  notice was  mailed to each of the cities  served by the
Company.  Over 90 of the 128 cities  declined  to  participate  in the  lawsuit.
However,  the  Company  has  pledged  that if any  final,  non-appealable  court
decision  in the  litigation  awards  a  judgement  against  it for a  franchise
underpayment,  the principles of that decision will be extended,  with regard to
the franchise  underpayment,  to the cities that decline to  participate  in the
litigation. In December 1999, the court ruled that the class of plaintiffs would
consist of approximately 30 cities. A trial date for June 2001 has been set.

        Although the Company  believes that it has  substantial  defenses to the
cities'  claims and intends to defend  itself  against  the  cities'  claims and
pursue its  counterclaims  vigorously,  management cannot predict the outcome of
this litigation or its impact on the Company's results of operations, cash flows
or financial  condition.  If the Company is  unsuccessful  in  defending  itself
against  these  claims it could  have a  material  adverse  effect on results of
operations, cash flows and financial condition.

NOx Reductions

        On April 19, 2000, the Texas Natural  Resource  Conservation  Commission
adopted  regulations  that require  reductions in nitrogen oxide (NOx) emissions
for existing permitted electric generating  facilities in the East Texas Region.
The Company's implementation date for the regulations is 2003.

        Preliminary  estimates  indicate that compliance with the NOx rule could
result in required  capital  expenditures of  approximately  $38 million for the
Company.  Since compliance costs cannot be estimated with certainty,  the actual
cost to comply could be significantly  different than the Company's  preliminary
estimate  depending  upon  the  compliance   alternatives  selected  to  achieve
reductions  in NOx  emissions.  Unless such costs are recovered  from  customers
through  regulated  rates  and/or  reflected  in  the  future  market  price  of
electricity when generation is deregulated,  they will have an adverse effect on
future results of operations and cash flows.

        Other

        The Company  continues to be involved in other matters  discussed in its
1999 Form 10-K.


<PAGE>



                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                            AND FINANCIAL CONDITION
 -----------------------------------------------------------------------------

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND

                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

         CPL's net income for the second  quarter  was $17 million or 32% higher
than the comparable period in 1999 and year-to-date net income was $8 million or
11% higher largely as a result of increased  sales to residential and commercial
customers for the  year-to-date  period and reductions in operating  expense for
the quarter and year-to-date periods.

        Income statement line items which changed significantly were:

                                     Increase (Decrease)

                            Second Quarter     Year-to-Date

                            (in millions)   %  (in millions)   %

Operating Revenues . . . . .     $54       14       $88       13
Fuel Expense . . . . . . . .      34       32        56       32
Purchased Power Expense. . .      19      115        26       88
Other Operation Expense. . .     (12)     (18)        1        1
Maintenance Expense. . . . .      (4)     (22)       (3)      (9)
Depreciation Expense . . . .      (2)      (5)        9       10
Taxes Other Than Federal
  Income Taxes . . . . . . .      (3)     (13)       (9)     (19)
Federal Income Taxes . . . .       7       23        -        -
Preferred Stock Dividends. .      (2)     (96)       (3)     (97)

         Operating  revenues  increased  as a result  of a rise in fuel  related
revenue due  primarily to  increased  fuel  revenues to recover  higher fuel and
purchased  power  expenses  and  increased  energy  sales  reflecting  a rise in
residential  and  commercial  customer  demand.  Higher fuel related  revenue is
generally offset by increases in fuel related expenses.

         A rise in the  average  price per unit of fuel,  resulting  mainly from
higher  spot  market  natural gas  prices,  accounted  for the  increase in fuel
expense.

         The significant  increase in purchased power expense resulted primarily
from additional economy, capacity and cogeneration purchase expenses.

         Other operation  expenses were reduced in the second quarter  primarily
due to a reduction in transmission  expenses that resulted from a new prices for
the Electric  Reliability Council of Texas (ERCOT)  transmission grid. Each year
ERCOT  establishes  new rates to  allocate  the costs of the Texas  transmission
system to Texas electric utilities.  The lower transmission expenses were offset
in part by higher administrative  expenses resulting from a change in the method
of recording vacation expense,  regulatory restructuring expense for unbundling,
consulting expenses for a sales tax audit and insurance expense. Other operation
expenses   increased   for  the  first  six  months  due   primarily  to  higher
administrative  expenses resulting from increased consulting expense for a sales
tax audit,  insurance expense,  regulatory  restructing expenses and a change in
the method of recording vacation expense. These increases were largely offset by
lower  transmission  expenses  resulting  from  the new  prices  for  the  ERCOT
transmission grid.

         Although STP Unit 1 underwent a maintenance outage in 2000, maintenance
expense  declined  due  to  a  reduction  in  fossil  power  plant  repairs  and
maintenance  activities.  In 1999 maintenance  activities included the refueling
and 10-year Nuclear Regulatory Commission required inspection of STP Unit 1.

         Depreciation and amortization  expenses decreased in the second quarter
reflecting the absence in 2000 of  amortization  for certain  regulatory  assets
that have been designated for  securitization.  The increase in depreciation and
amortization expenses for the year-to-date period reflects an accrual adjustment
in the  first  quarter  of 2000 for a 1999  earnings  cap  imposed  by the Texas
Commission  and  filed  in  March  2000,  offset  in  part  by  the  absence  of
amortization   in  2000   for   certain   regulatory   assets   designated   for
securitization.

         The  decline  in taxes  other  than  federal  income  taxes was  mainly
attributable  to a  favorable  accrual  adjustment  to ad valorem tax expense in
2000.

         Federal income tax expense attributable to utility operations increased
in the second quarter as a result of higher pre-tax income offset in part by the
absence of nondeductible  amortization associated with certain assets designated
for securitization.

         Preferred  stock  dividends  decreased as a result of the redemption of
CPL's money market and auction preferred stock in fourth quarter of 1999.

FINANCIAL CONDITION

         Total  plant and  property  additions  for the year to period  were $85
million.

                  In February  2000 the Company  sold $150  million of unsecured
floating rate notes.  The notes have a two-year  final  maturity of February 22,
2002,  but may be redeemed at par after one year.  The interest  rate will reset
quarterly at the then  current  three-month  London  Inter-Bank  Overnight  Rate
(LIBOR) plus 0.45%.  The initial  rate,  set February 18, 2000,  was 6.56%.  Net
proceeds of $149.4  million  were used to refund  $100  million of Series HH, 6%
First Mortgage Bonds maturing April 1, 2000 and to repay a portion of short-term
debt.

         In March 2000 the Company  reacquired  $50 million of its 7-1/2% Series
AA First Mortgage Bonds due March 1, 2020. The reacquisition was funded from the
issuance of Series 1999B in December 1999 the proceeds of which were placed in a
special deposit for reacquisition.

         The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.

MARKET RISKS

         The  Company  has  certain   market  risks  inherent  in  its  business
activities  from changes in interest  rates.  Market risk represents the risk of
loss that may impact the Company due to adverse changes in interest rates.

         The exposure to changes in interest rates from the Company's short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.

OTHER MATTERS

Texas Restructuring

    In June 1999  restructuring  legislation  was signed  into law in Texas that
will restructure the electric utility  industry (Texas  Legislation).  The Texas
Legislation, among other things:

o gives  customers of  investor-owned  utilities the opportunity to choose their
electric  provider  beginning  January 1, 2002;

o provides for the recovery of  regulatory  assets and of other  stranded  costs
through  securitization and non-bypassable wires charges;

o        requires reductions in nitrogen oxide and sulfur dioxide emissions;
o    provides  a rate  freeze  until  January  1,  2002  followed  by a 6%  rate
     reduction for residential  and small  commercial  customers,  an additional
     rate  reduction  for   low-income   customers  and  a  number  of  customer
     protections;

o sets an earnings test for the three years of rate freeze (1999 through  2001);
o sets  certain  limits for  ownership  and  control of  generation  capacity by
companies; and

o    requires a filing after January 10, 2004 to finalize  stranded  costs (2004
     true-up  proceeding)  including  final fuel recovery  balances,  regulatory
     assets, certain environmental costs,  accumulated excess earnings and other
     issues.  Delivery of electricity will continue to be the  responsibility of
     the local electric transmission and distribution utility

company  at  regulated  prices.  Each  electric  utility  must  submit a plan to
unbundle  its  business  activities  into a retail  electric  provider,  a power
generation company and a transmission and distribution utility.

     The Company and its affiliated  electric  utilities  which operate in Texas
filed  their  business  separation  (unbundling)  plan with the  Public  Utility
Commission  of Texas  (Texas  Commission)  on  January  10,  2000.  The  filings
described a financial and  accounting  functional  separation but not a legal or
structural separation, described how operations will be physically separated and
the functions they will perform,  described  competitive  energy  services,  and
provided a code of conduct.  In March 2000, the Texas  Commission ruled that the
plan was not in compliance with the Texas  Legislation and ordered revised plans
be submitted  to separate the  generation  business  from the wires  business in
separate  legal  entities by January 1, 2002.  In May 2000 a revised  separation
plan was  filed,  which  the  Texas  Commission  approved  on July 7, 2000 in an
interim order.

     Under the Texas  Legislation,  electric  utilities  are  allowed,  with the
approval  of  the  Texas   Commission,   to  recover  stranded  costs  including
generation-related  regulatory  assets that may not be  recoverable  in a future
competitive market. The approved costs can be refinanced through securitization,
which is a  financing  structure  designed  to  provide  state  sponsored  lower
financing  costs  than  are  available  through   conventional   public  utility
financings.  The securitized  amounts plus interest are then recovered through a
non-bypassable  wires charge.  In 1999 the Company filed an application with the
Texas  Commission  to  securitize  approximately  $1.27  billion  of its  retail
generation-related  regulatory  assets and  approximately  $47  million in other
qualified restructuring costs.

     On  February  10,  2000,  the  Texas  Commission   tentatively  approved  a
settlement,  which will  permit the  Company to  securitize  approximately  $764
million  of net  regulatory  assets.  The Texas  Commission's  order  authorized
issuance  of up to $797  million  of  securitization  bonds  including  the $764
million  for  recovery  of net  regulatory  assets  and $33  million  for  other
qualified  refinancing  costs.  The $764 million for recovery of net  regulatory
assets reflects the recovery of $949 million of regulatory assets offset by $185
million of customer benefits associated with accumulated  deferred income taxes.
The Company had previously proposed in its filing to flow these benefits back to
customers  over the 14-year  term of the  securitization  bonds.  The  remaining
regulatory assets originally requested by the Company in its 1999 securitization
request has been  included  in a March 2000  filing  with the Texas  Commission,
requesting  recovery of an additional $1.1 billion of stranded costs.  The March
2000 filing for $1.1 billion includes recovery of approximately  $800 million of
South Texas Project  (STP) nuclear plant costs  included in utility plant on the
Balance Sheet and  previously  identified as "Excess Cost Over Market" (ECOM) by
the Texas Commission for regulatory  purposes. A final determination on recovery
will  occur  as  part of the  2004  true-up  proceeding  and  the  total  amount
recoverable can be securitized.

     On  April  11,  2000,   four  parties   appealed  the  Texas   Commission's
securitization  order to the Travis County District Court.  One of these appeals
challenges  the  ability  to  recover  securitization  charges  under  the Texas
Constitution.  The Company  will not be able to issue the  securitization  bonds
until these appeals are resolved.  As a result, the securitization bonds are not
likely to be issued until 2001.

         The Company's  financial  statements  have  historically  reflected the
effects of applying  the  requirements  of  Statement  of  Financial  Accounting
Standards   (SFAS)  71,   "Accounting  for  the  Effects  of  Certain  Types  of
Regulation".  Pursuant to those requirements,  regulatory assets and liabilities
have been recorded to reflect the economic effect of cost-based regulation. When
a company  determines  that its operations or a segment of its operations are no
longer cost-based rate regulated, it is required to apply the provisions of SFAS
101 "Accounting for the Discontinuance of Application of Statement 71". Pursuant
to those requirements and further guidance provided in the Financial  Accounting
Standards  Board's  Emerging  Issues Task Force  (EITF)  Issue 97-4, a regulated
entity is required to write-off regulatory assets and liabilities related to the
portion of its  operations  whose rates will no longer be cost-based  regulated,
unless recovery of such amounts is provided through rates to be collected in the
portion  of  the   company's   operations   which   continue  to  be  regulated.
Additionally,  the  Company is  required to  determine  if any plant  assets are
impaired under SFAS 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of" and record any accounting impairment.

         As a result of the scheduled deregulation of generation under the Texas
Legislation,  the  application  of  SFAS 71 for the  generation  portion  of the
Company's  business in Texas was  discontinued in 1999.  Under the provisions of
EITF  97-4,  the  Company's   generation-related   net  regulatory  assets  were
transferred to the  transmission  and  distribution  portion of the business and
will be  amortized  as they are  recovered  through  charges to customers of the
regulated  distribution  business.  Since the  Company has net  stranded  costs,
management   currently  believes  that   substantially  all   generation-related
regulatory  assets should be recovered as provided by the Texas Legislation when
an electric  utility has a stranded  cost.  If future  events were to occur that
made the recovery of  regulatory  assets no longer  probable,  the Company would
write-off the portion of such assets deemed  unrecoverable  as a non-cash charge
to earnings.

     Recovery of  generation-related  regulatory  assets and stranded  costs are
subject to a final  determination  by the Texas  Commission  in 2004.  The Texas
Legislation  provides that all such finally  determined  stranded  costs will be
recovered.

         An  impairment  analysis  for  generation  assets  under  SFAS  121 was
completed  which  concluded  there was no  accounting  impairment  of generation
assets  at the  time  the  Company  discontinued  application  of  SFAS  71.  An
impairment  analysis involves  estimating future net cash flows arising from the
use of an asset. If the undiscounted net cash flows exceed the net book value of
the asset,  then there is no  impairment  of the asset to record for  accounting
purposes.  The Company will test its generation assets for impairment under SFAS
121 when circumstances change. However, on a discounted basis the cash flows are
less than the Company's  generating asset's net book value and together with the
Company's  generation-related  regulatory  assets create a recoverable  stranded
cost under the Texas Legislation.

         The Texas  Legislation  also  provides  that each year  during the 1999
through 2001 rate freeze period,  electric  utilities are subject to an earnings
test.  For electric  utilities with stranded costs any earnings in excess of the
most recently  approved cost of capital in its last rate case must be applied to
reduce stranded costs. As a result, the Company recorded a charge to earnings of
$32 million for the 1999 estimated excess earnings under the Texas  Legislation.
The Texas Commission is required under the Texas Legislation to certify that the
Company's  calculation  of excess  earnings for 1999 is correct by September 30,
2000.

         A Texas settlement  agreement in connection with the AEP and CSW merger
permits  the Company to apply for  regulatory  purposes up to $20 million of STP
ECOM Plant assets a year in 2000 and 2001 to reduce excess earnings,  if any.
For book purposes, plant assets will be depreciatied on a systematic and
rational basis unless impaired. To the extent excess  earnings  exceed
$20 million in 2000 or 2001 the Company will establish a regulatory liability
by a charge to earnings.

        Beginning  January  1,  2002,  fuel  costs  will not be subject to Texas
Commission fuel reconciliation proceedings.  Consequently, the Company will file
a final fuel  reconciliation with the Texas Commission which reconciles its fuel
costs through the period ending  December 31, 2001. Any final fuel balances will
be included for recovery in the 2004 true-up proceeding.

     The Company  continues to analyze the impact of the Texas electric  utility
industry  restructuring  legislation  on  its  operations.  Although  management
believes that the Texas Legislation  provides for full recovery of the Company's
stranded  costs  and that the  Company  does  not have a  recordable  accounting
impairment,  a final  determination  of whether the Company will  experience any
accounting loss from an inability to recover generation-related assets and other
restructuring  related  costs in Texas  cannot  be made  until  such time as the
litigation  and the regulatory  process are complete  following the 2004 true-up
proceeding. In the event the Company is unable after the 2004 true-up proceeding
to  recover  all or a  portion  of  its  generation-related  regulatory  assets,
stranded costs and other  restructuring  related costs, it could have a material
adverse  effect on results of  operations,  cash  flows and  possibly  financial
condition.

Municipal Franchise Fee Litigation

        The  Company  has  been  involved  in  litigation   regarding  municipal
franchise  fees in Texas as a result of a class action suit filed by the City of
San Juan,  Texas in 1996.  The City of San Juan  claims  the  Company  underpaid
municipal franchise fees and seeks damages of up to $300 million plus attorney's
fees. The Company filed a counterclaim for overpayment of franchise fees.

        During 1997, 1998 and 1999 the litigation moved procedurally through the
Texas Court System and was sent to mediation without resolution.

        In 1999 a class  notice was  mailed to each of the cities  served by the
Company.  Over 90 of the 128 cities  declined  to  participate  in the  lawsuit.
However,  the  Company  has  pledged  that if any  final,  non-appealable  court
decision  in the  litigation  awards  a  judgement  against  it for a  franchise
underpayment,  the principles of that decision will be extended,  with regard to
the franchise  underpayment,  to the cities that decline to  participate  in the
litigation. In December 1999, the court ruled that the class of plaintiffs would
consist of approximately 30 cities. A trial date for June 2001 has been set.

        Although the Company  believes that it has  substantial  defenses to the
cities'  claims and intends to defend  itself  against  the  cities'  claims and
pursue its  counterclaims  vigorously,  management cannot predict the outcome of
this litigation or its impact on the Company's results of operations, cash flows
or financial  condition.  If the Company is  unsuccessful  in  defending  itself
against  these  claims it could  have a  material  adverse  effect on results of
operations, cash flows and financial condition.


<PAGE>
<TABLE>
<CAPTION>


                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                   (UNAUDITED)

                                           Three Months Ended        Six Months Ended

                                                June 30,                 June 30,
                                         ---------------------    ---------------
                                           2000         1999        2000         1999
                                           ----         ----        ----         ----
                                                         (in thousands)
<S>                                      <C>          <C>         <C>          <C>
OPERATING REVENUES . . . . . . . . . . . $330,914     $301,419    $629,220     $580,486
                                         --------     --------    --------     --------
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   48,581       49,144      89,329       95,000
  Purchased Power. . . . . . . . . . . .   87,993       59,255     167,696      114,446
  Other Operation. . . . . . . . . . . .   50,332       46,514      95,621       92,483
  Maintenance. . . . . . . . . . . . . .   18,228       18,374      32,924       32,320
  Depreciation . . . . . . . . . . . . .   24,896       23,522      49,440       46,706
  Taxes Other Than Federal Income Taxes.   31,084       30,051      62,561       61,129
  Federal Income Taxes . . . . . . . . .   19,002       20,086      36,727       37,882
                                         --------     --------    --------     --------
          TOTAL OPERATING EXPENSES . . .  280,116      246,946     534,298      479,966
                                         --------     --------    --------     --------
OPERATING INCOME . . . . . . . . . . . .   50,798       54,473      94,922      100,520
NONOPERATING INCOME (LOSS) . . . . . . .    2,497         (478)      4,181         (117)
                                         --------     --------    --------     --------
INCOME BEFORE INTEREST CHARGES . . . . .   53,295       53,995      99,103      100,403
INTEREST CHARGES . . . . . . . . . . . .   17,960       19,436      36,297       38,426
                                         --------     --------    --------     --------
NET INCOME . . . . . . . . . . . . . . .   35,335       34,559      62,806       61,977
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      532          532       1,065        1,065
                                         --------     --------    --------     --------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 34,803     $ 34,027    $ 61,741     $ 60,912
                                         ========     ========    ========     ========



                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                                          Three Months Ended        Six Months Ended

                                                June 30,                 June 30,
                                         ---------------------    ---------------
                                           2000         1999        2000         1999
                                           ----         ----        ----         ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $249,872     $191,327    $246,584     $186,441
NET INCOME . . . . . . . . . . . . . . .   35,335       34,559      62,806       61,977
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   23,650       21,999      47,300       43,998
    Cumulative Preferred Stock . . . . .      438          438         875          875
  Capital Stock Expense. . . . . . . . .       95           95         191          191
                                         --------     --------    --------     --------
BALANCE AT END OF PERIOD . . . . . . . . $261,024     $203,354    $261,024     $203,354
                                         ========     ========    ========     ========

The common  stock of the  Company is wholly  owned by  American  Electric  Power
Company, Inc.

See Notes to Consolidated Financial Statements.

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


                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                            June 30,      December 31,
                                                              2000            1999
                                                           ----------     --------
                                                                 (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                        <C>             <C>
  Production . . . . . . . . . . . . . . . . . . . . .     $1,554,376      $1,544,858
  Transmission . . . . . . . . . . . . . . . . . . . .        354,598         350,826
  Distribution . . . . . . . . . . . . . . . . . . . .      1,071,101       1,032,550
  General. . . . . . . . . . . . . . . . . . . . . . .        146,656         141,137
  Construction Work in Progress. . . . . . . . . . . .         73,370          82,248
                                                           ----------      ----------
          Total Electric Utility Plant . . . . . . . .      3,200,101       3,151,619

  Accumulated Depreciation . . . . . . . . . . . . . .      1,253,003       1,210,994
                                                           ----------      ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      1,947,098       1,940,625
                                                           ----------      ----------


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        178,934         101,286
                                                           ----------      ----------


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          9,319           5,107
  Advances to Affiliates . . . . . . . . . . . . . . .         61,504            -
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .          2,376          77,418
    Affiliated Companies . . . . . . . . . . . . . . .         17,208          28,453
    Miscellaneous. . . . . . . . . . . . . . . . . . .          8,976           8,887
    Allowance for Uncollectible Accounts . . . . . . .           (567)         (3,045)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         18,106          21,484
  Materials and Supplies . . . . . . . . . . . . . . .         43,627          41,696
  Accrued Utility Revenues . . . . . . . . . . . . . .          1,701          48,117
  Energy Marketing and Trading Contracts . . . . . . .        572,306          90,103
  Prepayments. . . . . . . . . . . . . . . . . . . . .         49,868          37,969
                                                           ----------      ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        784,424         356,189
                                                           ----------      ----------


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        340,005         339,103
                                                           ----------      ----------


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         41,862          72,787
                                                           ----------      ----------



            TOTAL. . . . . . . . . . . . . . . . . . .     $3,292,323      $2,809,990
                                                           ==========      ==========

See Notes to Consolidated Financial Statements.

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


                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                           June 30,      December 31,
                                                             2000            1999
                                                          ----------     --------
                                                                (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  24,000,000 Shares

<S>                                                       <C>              <C>
    Outstanding - 16,410,426 Shares. . . . . . . . . .    $   41,026       $   41,026
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       573,063          572,873
  Retained Earnings. . . . . . . . . . . . . . . . . .       261,024          246,584
                                                          ----------       ----------
          Total Common Shareholder's Equity. . . . . .       875,113          860,483
  Cumulative Preferred Stock - Subject to
    Mandatory Redemption . . . . . . . . . . . . . . .        15,000           25,000
  Long-term Debt . . . . . . . . . . . . . . . . . . .       917,832          924,545
                                                          ----------       ----------

          TOTAL CAPITALIZATION . . . . . . . . . . . .     1,807,945        1,810,028
                                                          ----------       ----------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        41,535           43,056
                                                          ----------       ----------

CURRENT LIABILITIES:
  Preferred Stock Due Within One Year. . . . . . . . .        10,000             -
  Short-term Debt. . . . . . . . . . . . . . . . . . .          -              45,500
  Accounts Payable - General . . . . . . . . . . . . .        26,726           28,279
  Accounts Payable - Affiliated Companies. . . . . . .        66,503           52,776
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .        89,582          143,477
  Interest Accrued . . . . . . . . . . . . . . . . . .        13,854           13,936
  Energy Marketing and Trading Contracts . . . . . . .       564,793           87,911
  Other. . . . . . . . . . . . . . . . . . . . . . . .        36,648           34,375
                                                          ----------       ----------

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       808,106          406,254
                                                          ----------       ----------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       447,105          447,607
                                                          ----------       ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        43,022           44,716
                                                          ----------       ----------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       144,610           58,329
                                                          ----------       ----------

CONTINGENCIES (Note 6)

            TOTAL. . . . . . . . . . . . . . . . . . .    $3,292,323       $2,809,990
                                                          ==========       ==========

See Notes to Consolidated Financial Statements.

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


                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                 Six Months Ended

                                    June 30,

                                                               2000             1999
                                                               ----             ----
                                                                   (in thousands)

OPERATING ACTIVITIES:
<S>                                                           <C>             <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 62,806        $ 61,977
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . . .    49,709          46,837
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     6,783           2,697
    Deferred Investment Tax Credits. . . . . . . . . . . . .    (1,694)         (1,737)
    Deferred Collection of Fuel Costs (net). . . . . . . . .    (1,835)          4,252
    Amortization of Deferred Property Taxes. . . . . . . . .    33,721          34,406
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    83,720            (801)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     1,447          (2,186)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .    46,416         (13,498)
    Prepayments. . . . . . . . . . . . . . . . . . . . . . .   (11,899)         (8,717)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    12,174          (6,685)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .   (53,895)        (32,378)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .    (2,274)        (10,806)
                                                              --------        --------
        Net Cash Flows From Operating Activities . . . . . .   225,179          73,361
                                                              --------        --------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (59,372)        (46,005)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .       463             261
                                                              --------        --------
        Net Cash Flows Used For Investing Activities . . . .   (58,909)        (45,744)
                                                              --------        --------

FINANCING ACTIVITIES:
  Change in Short-term Debt (net). . . . . . . . . . . . . .   (45,500)         17,900
  Change in Advances to Affiliates (net) . . . . . . . . . .   (61,504)           -
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (6,879)           -
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (47,300)        (43,998)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .      (875)           (875)
                                                              --------        --------
        Net Cash Flows Used For Financing Activities . . . .  (162,058)        (26,973)
                                                              --------        --------

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     4,212             644
Cash and Cash Equivalents at Beginning of Period . . . . . .     5,107           7,206
                                                              --------        --------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  9,319        $  7,850
                                                              ========        ========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $34,547,000  and
  $36,491,000  and for income taxes was  $35,539,000 and $14,207,000 in 2000 and
  1999, respectively.  Noncash acquisitions under capital leases were $3,233,000
  and $4,043,000 in 2000 and 1999, respectively.

See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>


                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                  JUNE 30, 2000

                                   (UNAUDITED)

1.      GENERAL

               The  accompanying  unaudited  consolidated  financial  statements
        should  be  read  in   conjunction   with  the  1999  Annual  Report  as
        incorporated  in and  filed  with  the  Form  10-K.  In the  opinion  of
        management, the financial statements reflect all adjustments (consisting
        of only  normal  recurring  accruals)  which  are  necessary  for a fair
        presentation of the results of operations for interim periods.

2.      MONEY POOL

        On June 15,  2000,  the Company  became a  participant  in the  American
        Electric Power (AEP) System Money Pool (Money Pool). The Money Pool is a
        mechanism  structured to meet the short-term  cash  requirements  of the
        participants  with AEP Company,  Inc. acting as the primary  borrower on
        behalf  of the  Money  Pool.  The  Company's  affiliates  that  are U.S.
        domestic   electric   utility   operating   companies  are  the  primary
        participants in the Money Pool.

               The  operation  of the Money Pool is designed to match on a daily
        basis the available cash and borrowing requirements of the participants.
        Participants  with excess cash loan funds to the Money Pool reducing the
        amount of external  funds AEP Company,  Inc. needs to borrow to meet the
        short-term cash  requirements of other  participants  with advances from
        the Money Pool.  AEP Company,  Inc.  borrows the funds needed on a daily
        basis to meet the net cash requirements of the Money Pool  participants.
        A weighted  average daily interest rate which is calculated based on the
        outstanding  short-term  debt  borrowings  made by AEP Company,  Inc. is
        applied to each Money Pool participant's daily outstanding investment or
        debt position to determine interest income or interest expense. Interest
        income is included  in  nonoperating  income,  and  interest  expense is
        included  in  interest  charges.  As a result of  becoming  a Money Pool
        participant,  the Company retired its short-term  debt. At June 30, 2000
        the  Company  was a net  investor  in the  Money  Pool and  reports  its
        investment  in the Money Pool as Advances to  Affiliates  on the Balance
        Sheets.

3.      RATE MATTERS

            As  discussed  in  Note 2 of the  Notes  to  Consolidated  Financial
      Statements of the 1999 Annual  Report,  the AEP System  companies  filed a
      settlement  agreement  for Federal  Energy  Regulatory  Commission  (FERC)
      approval related to an open access transmission tariff. The Company made a
      provision in 1999 for an agreed to refund including interest.


<PAGE>


            On March 16, 2000, the FERC approved the settlement  agreement filed
      in December  1999  resolving  the issues on  rehearing  of a July 30, 1999
      order.  Under terms of the  settlement,  AEP is  required to make  refunds
      retroactive to September 7, 1993 to certain customers affected by the July
      30, 1999 FERC order.  The refunds were made in two  payments.  Pursuant to
      FERC orders the first  payment  was made in  February  2000 and the second
      payment was made on August 1, 2000. In addition, a new lower rate of $1.55
      kw/month was made effective January 1, 2000, for all transmission  service
      customers and a rate of $1.42 kw/month was  established and took effect on
      June 16, 2000 after the consummation of the AEP and Central and South West
      Corporation merger. Prior to January 1, 2000, the rate was $2.04 kw/month.
      Unless the  Company  and the  market  grow the  volume of  physical  power
      transactions  to increase  utilization  of the AEP  System's  transmission
      lines, the new open access  transmission rate will adversely impact future
      results of operations and cash flows.

4.      FACTORING OF RECEIVABLES

        In June 2000,  Columbus  Southern Power Company entered into a factoring
       arrangement  with an affiliate,  CSW Credit,  Inc. Under this arrangement
       the  Company  sells  without   recourse  its  retail  customer   accounts
       receivable  and  accrued  utility  revenue  balances to CSW Credit and is
       charged  a fee  based  on CSW  Credit's  financing  costs,  uncollectible
       accounts  experience  for the Company's  receivables  and  administrative
       costs. The costs of factoring customer accounts receivable is reported as
       an operating  expense.  At June 30, 2000 the amount of factored  accounts
       receivable and accrued utility revenues was $119 million.
<PAGE>
5.    OHIO RESTRUCTURING LAW AND TRANSITION PLAN FILING
      -------------------------------------------------

            As  discussed  in  Note 4 of the  Notes  to  Consolidated  Financial
      Statements in the 1999 Annual Report, the Ohio Electric  Restructuring Act
      of 1999 (the Act) provides for,  among other  things,  customer  choice of
      electricity   supplier,  a  residential  rate  reduction  of  5%  for  the
      generation  portion of rates and a freezing of generation  rates including
      fuel rates  beginning  on January 1,  2001.  The Act also  provides  for a
      five-year  transition  period  to move  from  cost-based  rates to  market
      pricing  for  generation  services.  It  authorizes  the Public  Utilities
      Commission  of Ohio  (PUCO) to address  certain  major  transition  issues
      including  unbundling  of rates  and the  recovery  of  generation-related
      transition costs which include  regulatory  assets,  asset impairments and
      other stranded costs,  employee  severance and retraining costs,  consumer
      education costs and other costs.  Stranded costs are generation costs that
      are not deemed to be recoverable in a competitive market.

            On March 28, 2000 the PUCO staff issued its report on the  Company's
      transition plan filing.  On May 8, 2000, a stipulation  agreement  between
      the  Company,  the PUCO  staff,  the Ohio  Consumers'  Counsel  and  other
      concerned parties was filed with the PUCO for approval. The key provisions
      of the stipulation agreement are:

      -     Recovery of  generation-related  regulatory  assets over eight years
            will be  through a frozen  transition  rate for the first five years
            and a wires charge for the remaining years.

      - A shopping incentive (a price credit) of 2.5 mills/kwh for the first 25%
      of residential customers that switch suppliers. ? The Company is to absorb
      the first $20 million of consumer education, implementation and transition
      plan filing costs

            with deferral of the remaining costs,  plus a carrying charge,  as a
            regulatory asset for recovery in future distribution rates.

      -     The  Company  and its  affiliate,  Ohio  Power  Company,  will  make
            available a fund of up to $10  million to  reimburse  customers  who
            choose to  purchase  their  power from  another  company for certain
            transmission charges imposed by Pennsylvania - New Jersey - Maryland
            transmission  organization (PJM) and/or a midwest independent system
            operator (Midwest ISO) on generation  originating in the Midwest ISO
            or PJM areas.

      -     The   statutory  5%  reduction  in  the   generation   component  of
            residential  tariffs will remain in effect for the entire transition
            period.

      -     The  Company's  request  for a $40  million  gross  receipts  tax
            rider to recover  duplicate  gross  receipts  tax will be
            separately litigated.

            Hearings on the  stipulation  and the gross  receipts tax issue were
      held in June 2000.  Approval of the  stipulation  agreement by the PUCO is
      pending.

            Management has concluded  that as of June 30, 2000 the  requirements
      to  apply  Statement  of  Financial   Accounting   Standards   (SFAS)  71,
      "Accounting for the Effects of Certain Types of  Regulation,"  continue to
      be met since  the  Company's  rates for  generation  will  continue  to be
      cost-based regulated until the PUCO takes action on the transition plan as
      required by the Act. The  establishment of rates and wires charges under a
      PUCO  approved  transition  plan will enable the Company to determine  its
      ability to recover stranded costs including  regulatory  assets, and other
      transition costs, a requirement to discontinue the application of SFAS 71.

            When the transition plan and transition  period tariff schedules are
      approved,  the  application of SFAS 71 will be  discontinued  for the Ohio
      retail  jurisdictional  portion  of the  generating  business.  Management
      expects this to occur when the PUCO approves the stipulation agreement for
      the Company's transition plan filing. The Act requires that the PUCO issue
      its order to approve  transition  plan  filings no later than  October 31,
      2000.

            Upon the  discontinuance  of SFAS 71 the Company  will have to write
      off its Ohio  jurisdictional  generation-related  regulatory assets to the
      extent that they cannot be  recovered  under the tariff  schedules  in the
      transition  plan  approved  by the PUCO and  record  any asset  accounting
      impairments in accordance with SFAS 121, "Accounting for the Impairment of
      Long-lived  Assets  and  for  Long-lived  Assets  to Be  Disposed  Of." An
      impairment loss would be recorded,  under SFAS 121, to the extent that the
      cost of  generating  assets  cannot be  recovered  through  non-discounted
      generation-related revenues during the transition period and future market
      prices.  Until the PUCO  completes  its  regulatory  process and issues an
      order  related to the  Company's  transition  plan, it is not possible for
      management  to determine  if any of the  Company's  generating  assets are
      impaired for accounting purposes in accordance with SFAS 121.

            The amount of  regulatory  assets  recorded on the books at June 30,
      2000 applicable to the Ohio retail  jurisdictional  generating business is
      $301  million  before  related tax effects.  Recovery of these  regulatory
      assets is being sought as a part of the  Company's  Ohio  transition  plan
      filing.  Based on current projections of future market prices, the Company
      does  not  anticipate  that it will  experience  material  tangible  asset
      accounting  impairment  write-offs.  Whether the Company  will  experience
      material  regulatory  asset  write-offs  will  depend on whether  the PUCO
      approves the  Company's  stipulation  agreement  which  provides for their
      recovery.

            A  determination  of whether the Company will  experience  any asset
      impairment loss regarding its Ohio retail jurisdictional generating assets
      and any loss from a possible inability to recover Ohio  generation-related
      regulatory assets and other transition costs cannot be made until the PUCO
      takes action on the Company's stipulation agreement.  Should the PUCO fail
      to fully approve the Company's  stipulation  agreement and its  transition
      tariff    schedules,    which   include    recovery   of   the   Company's
      generation-related  regulatory assets, stranded costs and other transition
      costs,  it could have a material  adverse effect on results of operations,
      cash flows and possibly financial condition.


<PAGE>


6.    CONTINGENCIES

      COLI Litigation

            As  discussed  in  Note 5 of the  Notes  to  Consolidated  Financial
      Statements  in the  1999  Annual  Report,  the  deductibility  of  certain
      interest deductions related to AEP?s corporate owned life insurance (COLI)
      program  for  taxable  years  1991  through  1996 is under  review  by the
      Internal Revenue Service (IRS).  Adjustments have been or will be proposed
      by the IRS  disallowing  COLI interest  deductions.  A disallowance of the
      COLI interest  deductions  through June 30, 2000 would reduce  earnings by
      approximately $43 million (including interest).

            The Company made payments of taxes and interest attributable to COLI
      interest  deductions  for  taxable  years 1991  through  1998 to avoid the
      potential  assessment  by the  IRS of any  additional  above  market  rate
      interest on the contested amount.  The payments to the IRS are included on
      the consolidated  balance sheet in other property and investments  pending
      the  resolution  of this  matter.  The Company is seeking  refund  through
      litigation of all amounts paid plus interest.

            In order to resolve this issue,  the Company  filed suit against the
      United States in the U.S. District Court for the Southern District of Ohio
      in 1998. In 1999 a U.S. Tax Court judge decided in the  Winn-Dixie  Stores
      v. Commissioner case that a corporate  taxpayer's COLI interest  deduction
      should  be  disallowed.   Notwithstanding  the  Tax  Court's  decision  in
      Winn-Dixie,  management  has made no provision  for any  possible  adverse
      earnings impact from this matter because it believes, and has been advised
      by outside counsel, that it has a meritorious position and will vigorously
      pursue  its  lawsuit.  In the  event  the  resolution  of this  matter  is
      unfavorable,  it  will  have a  material  adverse  impact  on  results  of
      operations, cash flows and possibly financial condition.

      Federal EPA Complaint and Notice of Violation


<PAGE>


            As  discussed  in  Note 5 of the  Notes  to  Consolidated  Financial
      Statements  in the 1999 Annual  Report,  the Company has been  involved in
      litigation regarding generating plant emissions. Notices of Violation were
      issued  and a  complaint  was filed by the U.S.  Environmental  Protection
      Agency (Federal EPA) in the U.S.  District Court for the Southern District
      of Ohio that alleges the Company and certain  other  affiliated  utilities
      made  modifications  to  generating  units at certain of their  coal-fired
      generating  plants  over the course of the past 25 years that  extend unit
      operating   lives  or  increase  unit   generating   capacity   without  a
      preconstruction  permit in violation  of the Clean Air Act. The  complaint
      was amended in March 2000 to add allegations for certain  generating units
      previously  named in the  complaint and to include  additional  AEP System
      generating  units previously named only in the Notices of Violation in the
      complaint.  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.

            A number of  northeastern  and eastern  states were granted leave to
      intervene in the Federal EPA's action  against the Company under the Clean
      Air Act. A lawsuit  against  power  plants  owned by the Company  alleging
      similar  violations  to those in the Federal EPA  complaint and Notices of
      Violation  was filed by a number of special  interest  groups and has been
      consolidated with the Federal EPA action.

            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).  Civil penalties,  if ultimately  imposed by the court,
      and the cost of any required new pollution control equipment, if the court
      accepts Federal EPA's contentions, could be substantial.

            On May 10,  2000,  the  Company  filed  motions  to  dismiss  all or
      portions of the  complaints.  Briefing on these  motions was  completed on
      August  2,  2000.   Management   believes  its  maintenance,   repair  and
      replacement  activities  were in  conformity  with the  Clean  Air Act and
      intends to vigorously pursue its defense of this matter.

            In the event the Company does 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 transition rates,  stranded costs wires
      charges and/or future market prices for electricity.

      NOx Reductions

            As  discussed  in  Note 6 of the  Notes  to  Consolidated  Financial
      Statements of the 1999 Annual  Report,  the Federal EPA had issued a final
      rule (the NOx rule) that requires substantial reductions in nitrogen oxide
      (NOx)  emissions in 22 eastern states,  including  certain states in which
      the AEP System?s  generating  plants are located.  A number of  utilities,
      including  certain AEP System  companies,  had filed  petitions  seeking a
      review of the final rule in the U.S.  Court of Appeals for the District of
      Columbia  Circuit  (Appeals  Court).   In  May  1999,  the  Appeals  Court
      indefinitely  stayed the  requirement  that  states  develop  revised  air
      quality programs to impose the NOx reductions but did not,  however,  stay
      the final  compliance date of May 1, 2003. In March 2000 the Appeals Court
      issued a decision  generally  upholding  the NOx rule.  On April 20, 2000,
      certain AEP System companies and other  petitioners filed for rehearing of
      this decision  including a rehearing by the entire Appeals Court.  On June
      22, 2000,  the Appeals  Court denied the petition for rehearing and lifted
      the stay  related  to the  states'  development  of  revised  air  quality
      programs to impose the NOx reductions. The petition for a rehearing before
      the entire Appeals Court was also denied. The AEP System companies subject
      to the NOx rule plan to appeal to the U.S. Supreme Court.


<PAGE>


            Preliminary  estimates  indicate that  compliance  with the NOx rule
      upheld by the Appeals Court could result in required capital  expenditures
      of  approximately  $136 million for the Company.  Since  compliance  costs
      cannot be  estimated  with  certainty,  the actual cost to comply could be
      significantly  different than the Company's preliminary estimate depending
      upon the  compliance  alternatives  selected to achieve  reductions in NOx
      emissions.   Unless  such  costs  are  recovered  from  customers  through
      regulated  transition  rates,  stranded  costs wire charges  and/or future
      market prices for electricity,  they will have an adverse effect on future
      results of operations, cash flows and possibly financial condition.

        Other

               The Company  continues  to be involved in certain  other  matters
discussed in its 1999 Annual Report.

7.       FINANCING ACTIVITIES

        The Company  redeemed 100,000 shares of its 7% series of preferred stock
        on August 1, 2000.  The Company has in the past,  and may in the future,
        acquire  outstanding  debt and preferred stock securities in open market
        transactions.


<PAGE>



                                      F-115

                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999

                                       AND

                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

     Net income increased 2% for the quarter and 1% for the year-to-date  period
reflecting  an  increase  in  nonoperating  income and a  reduction  in interest
charges.

        Income statement line items which changed significantly were:

                                    Increase (Decrease)

                            Second Quarter        Year-to-Date

                          (in millions)   %    (in millions)   %
                          -------------   -    -------------   -

Operating Revenues. . . . .    $29       10         $49        8
Fuel. . . . . . . . . . . .     (1)      (1)         (6)      (6)
Purchased Power . . . . . .     29       48          53       47
Other Operation . . . . . .      4        8           3        3
Depreciation. . . . . . . .      1        6           3        6
Nonoperating Income . . . .      3      N.M.          4      N.M.
Interest Charges. . . . . .     (1)      (8)         (2)      (6)

N.M. = Not Meaningful

        The increases in operating  revenues and purchased power expense are due
to a  significant  increase in American  Electric  Power  System Power Pool (AEP
Power Pool)  transactions.  The Company as a member of the AEP Power Pool shares
in the revenues and costs of the AEP Power Pool's wholesale  marketing sales and
forward trades to neighboring utility systems and power marketers. The Company's
share of these AEP Power Pool  transactions  within  the AEP System  traditional
marketing area (within two transmission  systems of the AEP System) are recorded
as operating  revenues and  purchases.  Forward  trading sales and purchases are
recorded  on a net basis in  operating  revenues.  As a result of an  affiliated
company's  major  industrial  customer's  decision not to continue its purchased
power  agreement,  additional power was available to the AEP Power Pool for sale
on the wholesale  market  accounting for the increase in the Company's  revenues
and purchased power expense.

        Fuel expense  decreased in the year-to-date  period due to the operation
of the fuel  clause  adjustment  mechanism  which  resulted  in a credit to fuel
expense for under recovery of emission  allowance costs which were deferred as a
regulatory  asset  for  future  recovery  through  the fuel  clause  or  through
transition recovery mechanisms under Ohio restructuring legislation. The Company
has requested  recovery of the projected  deferred  fuel cost  regulatory  asset
balance at December 31, 2000 as part of its transition plan filing  discussed in
Note 5 of the Notes to Consolidated Financial Statements.

        The cost of  factoring  of  accounts  receivable  to an  affiliate,  CSW
Credit, Inc. accounted for the increase in other operation expense.

        Additional  investment in distribution plant resulted in the increase in
depreciation expense.

        The increase in nonoperating  income was due to an increase in net gains
from non-regulated AEP Power Pool power 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 Pool's forward electricity trading
transactions  outside of the AEP System  traditional  marketing area (beyond two
transmission  systems  from  the  AEP  System)  and  for  speculative  financial
transactions  (options,  futures,  swaps) is included in nonoperating income. In
the year-to-date period the increase in nonoperating income is also attributable
to the  reversal  in the first  quarter  of 2000 of a  provision  for  potential
liability for clean-up of possible environmental  contamination from underground
storage tanks at a Company  facility after the state of Ohio reviewed the matter
and determined that no further corrective action would be required.

     The  decline  in  interest  charges  was due to a decrease  in  outstanding
long-term  debt  balances  reflecting  the partial  redemption  in 1999  without
replacement  of three  different  series of first  mortgage  bonds  totaling $36
million.

Market Risks
------------
        The Company has certain market risks inherent in its business activities
from changes in electricity  commodity  prices and interest  rates.  Market risk
represents  the risk of loss that may impact the Company due to adverse  changes
in commodity market prices and interest rates. The Company's  exposure to market
risk  from  the  trading  of  electricity  and  related   financial   derivative
instruments,  which are allocated to the Company  through the American  Electric
Power  System  Power  Pool,  were less than $5 million  at June 30,  2000 and $3
million at December 31, 1999 based on the use of a risk measurement  model which
calculates  Value at Risk (VaR).  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 three-day holding period.

        The exposure to changes in interest rates from the Company's  short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.


<PAGE>
<TABLE>
<CAPTION>


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                   (UNAUDITED)

                                          Three Months Ended           Six Months Ended

                                               June 30,                    June 30,
                                         --------------------       ---------------
                                           2000        1999            2000        1999
                                           ----        ----            ----        ----
                                                         (in thousands)

<S>                                      <C>         <C>             <C>         <C>
OPERATING REVENUES . . . . . . . . . . . $362,272    $336,553        $706,258    $670,666
                                         --------    --------        --------    --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   43,844      42,123          91,704      83,923
  Purchased Power. . . . . . . . . . . .   96,222      67,510         181,328     129,825
  Other Operation. . . . . . . . . . . .  151,328     115,258         284,879     206,833
  Maintenance. . . . . . . . . . . . . .   55,841      24,621         111,225      55,823
  Depreciation and Amortization. . . . .   38,499      37,495          76,710      74,480
  Taxes Other Than Federal Income Taxes.   16,787      17,256          33,996      36,285
  Federal Income Tax Expense (Credit). .  (21,650)      5,324         (39,734)     17,693
                                         --------    --------        --------    --------

          TOTAL OPERATING EXPENSES . . .  380,871     309,587         740,108     604,862
                                         --------    --------        --------    --------

OPERATING INCOME (LOSS). . . . . . . . .  (18,599)     26,966         (33,850)     65,804
NONOPERATING INCOME. . . . . . . . . . .    2,637       1,556           3,202       3,291
                                         --------    --------        --------    --------
INCOME (LOSS) BEFORE INTEREST CHARGES. .  (15,962)     28,522         (30,648)     69,095
INTEREST CHARGES . . . . . . . . . . . .   23,219      18,777          45,086      39,280
                                         --------    --------        --------    --------
NET INCOME (LOSS). . . . . . . . . . . .  (39,181)      9,745         (75,734)     29,815
PREFERRED STOCK DIVIDEND REQUIREMENTS. .    1,153       1,215           2,313       2,429
                                         --------    --------        --------    --------
EARNINGS (LOSS) APPLICABLE TO
  COMMON STOCK . . . . . . . . . . . . . $(40,334)   $  8,530        $(78,047)   $ 27,386
                                         ========    ========        ========    ========


                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                                          Three Months Ended          Six Months Ended

                                               June 30,                   June 30,
                                         --------------------       --------------
                                           2000        1999           2000        1999
                                           ----        ----           ----        ----
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $102,364    $243,346       $166,389    $253,154
NET INCOME (LOSS). . . . . . . . . . . .  (39,181)      9,745        (75,734)     29,815
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .     -         28,664         26,290      57,328
    Cumulative Preferred Stock . . . . .    2,243       1,182          3,368       2,364
  Capital Stock Expense. . . . . . . . .       10          33             67          65
                                         --------    --------       --------    --------

BALANCE AT END OF PERIOD . . . . . . . . $ 60,930    $223,212       $ 60,930    $223,212
                                         ========    ========       ========    ========

The common  stock of the  Company is wholly  owned by  American  Electric  Power
Company, Inc.

See Notes to Consolidated Financial Statements.

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


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                            June 30,      December 31,
                                                              2000            1999
                                                           ----------     --------
                                                                 (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                        <C>             <C>
  Production . . . . . . . . . . . . . . . . . . . . .     $2,594,194      $2,587,288
  Transmission . . . . . . . . . . . . . . . . . . . .        938,047         928,758
  Distribution . . . . . . . . . . . . . . . . . . . .        839,648         818,697
  General (including nuclear fuel) . . . . . . . . . .        266,626         244,981
  Construction Work in Progress. . . . . . . . . . . .        228,404         190,303
                                                           ----------      ----------
          Total Electric Utility Plant . . . . . . . .      4,866,919       4,770,027
  Accumulated Depreciation and Amortization. . . . . .      2,255,262       2,194,397
                                                           ----------      ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,611,657       2,575,630
                                                           ----------      ----------



NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
  FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . .        739,676         707,967
                                                           ----------      ----------


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        294,802         213,658
                                                           ----------      ----------



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          7,010           3,863
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         45,558          91,268
    Affiliated Companies . . . . . . . . . . . . . . .         32,482          48,901
    Miscellaneous. . . . . . . . . . . . . . . . . . .         18,120          18,644
    Allowance for Uncollectible Accounts . . . . . . .           (705)         (1,848)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         28,026          27,597
  Materials and Supplies . . . . . . . . . . . . . . .         85,184          84,149
  Accrued Utility Revenues . . . . . . . . . . . . . .           -             44,428
  Energy Trading Contracts . . . . . . . . . . . . . .        622,135          97,946
  Prepayments. . . . . . . . . . . . . . . . . . . . .          6,628           7,631
                                                           ----------      ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        844,438         422,579
                                                           ----------      ----------



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        582,529         624,810
                                                           ----------      ----------



DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         32,606          32,052
                                                           ----------      ----------



            TOTAL. . . . . . . . . . . . . . . . . . .     $5,105,708      $4,576,696
                                                           ==========      ==========

See Notes to Consolidated Financial Statements.

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


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                           June 30,       December 31,
                                                             2000             1999
                                                          ----------      --------
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  2,500,000 Shares

<S>                                                       <C>              <C>
    Outstanding - 1,400,000 Shares . . . . . . . . . .    $   56,584       $   56,584
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       733,005          732,739
  Retained Earnings. . . . . . . . . . . . . . . . . .        60,930          166,389
                                                          ----------       ----------
          Total Common Shareholder's Equity. . . . . .       850,519          955,712
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .         8,736            9,248
    Subject to Mandatory Redemption. . . . . . . . . .        64,945           64,945
  Long-term Debt . . . . . . . . . . . . . . . . . . .     1,092,546        1,126,326
                                                          ----------       ----------

          TOTAL CAPITALIZATION . . . . . . . . . . . .     2,016,746        2,156,231
                                                          ----------       ----------

OTHER NONCURRENT LIABILITIES:
  Nuclear Decommissioning. . . . . . . . . . . . . . .       531,760          501,185
  Other. . . . . . . . . . . . . . . . . . . . . . . .       195,012          242,522
                                                          ----------       ----------

          TOTAL OTHER NONCURRENT LIABILITIES . . . . .       726,772          743,707
                                                          ----------       ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .       190,000          198,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .          -             224,262
  Advances from Affiliates . . . . . . . . . . . . . .       331,852             -
  Accounts Payable - General . . . . . . . . . . . . .        47,008           78,784
  Accounts Payable - Affiliated Companies. . . . . . .        48,801           31,118
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .        20,702           48,970
  Interest Accrued . . . . . . . . . . . . . . . . . .        17,851           13,955
  Obligations Under Capital Leases . . . . . . . . . .        46,763           11,072
  Energy Trading Contracts . . . . . . . . . . . . . .       614,124           95,564
  Other. . . . . . . . . . . . . . . . . . . . . . . .       101,669           91,684
                                                          ----------       ----------

          TOTAL CURRENT LIABILITIES. . . . . . . . . .     1,418,770          793,409
                                                          ----------       ----------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       600,343          622,157
                                                          ----------       ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       117,854          121,627
                                                          ----------       ----------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .        83,152           85,005
                                                          ----------       ----------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       142,071           54,560
                                                          ----------       ----------

COMMITMENTS AND CONTINGENCIES (Note 7)

            TOTAL. . . . . . . . . . . . . . . . . . .    $5,105,708       $4,576,696
                                                          ==========       ==========

See Notes to Consolidated Financial Statements.

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


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                Six Months Ended

                                                              June 30,
                                                     -----------------
                                                        2000           1999
                                                        ----           ----
                                                           (in thousands)

OPERATING ACTIVITIES:
<S>                                                  <C>             <C>
  Net Income (Loss). . . . . . . . . . . . . . . . . $ (75,734)      $ 29,815
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . .    81,423         76,431
    Amortization of Incremental Nuclear
      Refueling Outage Expenses (net). . . . . . . .     3,722          4,695
    Unrecovered Fuel and Purchased Power Costs . . .    18,751        (63,922)
    Amortization (Deferral) of Nuclear
        Outage Costs (net). . . . . . . . . . . . . . .    20,000        (60,000)
    Deferred Federal Income Taxes. . . . . . . . . .   (12,038)        23,448
    Deferred Investment Tax Credits. . . . . . . . .    (3,773)        (3,796)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . .    61,510        (10,474)
    Fuel, Materials and Supplies . . . . . . . . . .    (1,464)       (23,541)
    Accrued Utility Revenues . . . . . . . . . . . .    44,428          5,923
    Accounts Payable . . . . . . . . . . . . . . . .   (14,093)        (7,232)
    Taxes Accrued. . . . . . . . . . . . . . . . . .   (28,268)       (23,862)
    Revenue Refunds Accrued. . . . . . . . . . . . .     8,365         55,000
    Dividends Declared . . . . . . . . . . . . . . .     1,119         28,663
  Other (net). . . . . . . . . . . . . . . . . . . .   (39,123)       (25,103)
                                                     ---------      ---------
        Net Cash Flows From Operating Activities . .    64,825          6,045
                                                     ---------      ---------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . .   (93,002)       (63,316)
  Other. . . . . . . . . . . . . . . . . . . . . . .       587          1,198
                                                     ---------      ---------
        Net Cash Flows Used for Investing Activities   (92,415)       (62,118)
                                                     ---------      ---------

FINANCING ACTIVITIES:
  Retirement of Long-term Debt . . . . . . . . . . .   (48,000)       (65,000)
  Change in Short-term Debt (net). . . . . . . . . .  (224,262)       160,480
  Change in Advances from Affiliates (net) . . . . .   331,852           -
  Retirement of Cumulative Preferred Stock . . . . .      (314)            (5)
  Dividends Paid on Common Stock . . . . . . . . . .   (26,290)       (28,664)
  Dividends Paid on Cumulative Preferred Stock . . .    (2,249)        (2,364)
                                                     ---------      ---------
        Net Cash Flows From Financing Activities . .    30,737         64,447
                                                     ---------      ---------

Net Increase in Cash and Cash Equivalents. . . . . .     3,147          8,374
Cash and Cash Equivalents at Beginning of Period . .     3,863         12,465
                                                     ---------      ---------
Cash and Cash Equivalents at End of Period . . . . . $   7,010      $  20,839
                                                     =========      =========

Supplemental Disclosure:
  Cash paid  (received) for interest net of capitalized  amounts was $39,686,000
  and $38,775,000 and for income taxes was  $(2,365,000) and $19,217,000 in 2000
  and  1999,  respectively.  Noncash  acquisitions  under  capital  leases  were
  $15,423,000 and $6,901,000 in 2000 and 1999, respectively.

See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                  JUNE 30, 2000

                                   (UNAUDITED)

1.      GENERAL

               The  accompanying  unaudited  consolidated  financial  statements
        should  be  read  in   conjunction   with  the  1999  Annual  Report  as
        incorporated  in and  filed  with the Form  10-K.  Certain  prior-period
        amounts   have  been   reclassified   to   conform   to   current-period
        presentation.  In the opinion of  management,  the financial  statements
        reflect all adjustments  (consisting of only normal recurring  accruals)
        which are necessary for a fair presentation of the results of operations
        for interim periods.

2.    COOK NUCLEAR PLANT SHUTDOWN
      ---------------------------

            As  discussed  in  Note 2 of the  Notes  to  Consolidated  Financial
      Statements in the 1999 Annual Report, the Cook Nuclear Plant was shut down
      in September  1997 due to questions  regarding the  operability of certain
      safety  systems that arose during a Nuclear  Regulatory  Commission  (NRC)
      architect  engineer  design  inspection.  Cook Plant is a two-unit,  2,110
      megawatt plant.

            On July 5, 2000, Cook Nuclear Plant Unit 2, the first unit scheduled
      to restart, reached 100% power completing its restart process.

            On July 26,  2000,  the Company  announced  that the restart of Cook
      Nuclear  Plant  Unit 1  would  cost an  additional  $145  million  and was
      scheduled  to occur in the first  quarter  of 2001.  Unforeseen  issues or
      difficulties encountered in preparing Unit 1 for restart could potentially
      delay its return to service.

            Expenditures  to restart the Cook units had been  estimated to total
      approximately  $574 million.  The additional $145 million raises the total
      estimate to $719  million.  Through June 30,  2000,  $534 million has been
      spent.  For the six months  ended  June 30,  2000,  restart  costs of $181
      million have been  recorded in other  operation and  maintenance  expense,
      including amortization of $20 million of restart costs previously deferred
      in  accordance  with  settlement  agreements  in the Indiana and  Michigan
      retail  jurisdictions.  At June 30, 2000,  deferred  restart costs of $140
      million are included in regulatory assets.

            The costs of the  extended  outage and restart  efforts  will have a
      material  adverse effect on future  results of operations,  cash flows and
      possibly  financial  condition  until the second  unit is  restarted.  The
      amortization  of restart costs deferred under Indiana and Michigan  retail
      jurisdiction  settlement  agreements  will  adversely  effect  results  of
      operations  through 2003 when the  amortization  period  ends.  The annual
      amortization  of the restart cost  deferrals  is $40  million.  Management
      believes that Unit 1 of the Cook Plant will also be successfully  returned
      to service.  However,  if for some  unknown  reason it is not  returned to
      service  or its  return is  delayed  significantly  it would  have an even
      greater  material  adverse effect on future  results of  operations,  cash
      flows and financial condition.


<PAGE>



3.      FINANCING ACTIVITIES

               In March 2000 the Company  redeemed  $48 million of 6.40%  series
        first mortgage  bonds at maturity.  The Company has in the past, and may
        in the future,  acquire  outstanding debt and preferred stock securities
        in open market transactions.

4.      MONEY POOL

            On June 15, 2000,  the Company  became a participant in the American
        Electric Power (AEP) System Money Pool (Money Pool). The Money Pool is a
        mechanism  structured to meet the short-term  cash  requirements  of the
        participants  with AEP Company,  Inc. acting as the primary  borrower on
        behalf  of the  Money  Pool.  The  Company's  affiliates  that  are U.S.
        domestic   electric   utility   operating   companies  are  the  primary
        participants in the Money Pool.

            The  operation  of the Money  Pool is  designed  to match on a daily
        basis the available cash and borrowing requirements of the participants.
        Participants  with excess cash loan funds to the Money Pool reducing the
        amount of external  funds AEP Company,  Inc. needs to borrow to meet the
        short-term cash  requirements of other  participants  with advances from
        the Money Pool.  AEP Company,  Inc.  borrows the funds needed on a daily
        basis to meet the net cash requirements of the Money Pool  participants.
        A weighted  average daily interest rate which is calculated based on the
        outstanding  short-term  debt  borrowings  made by AEP Company,  Inc. is
        applied to each Money Pool participant's daily outstanding investment or
        debt position to determine interest income or interest expense. Interest
        income is included  in  nonoperating  income,  and  interest  expense is
        included  in  interest  charges.  As a result of  becoming  a Money Pool
        participant,  the Company  retired its  short-term  debt and reports its
        borrowing from the Money Pool as Advances from Affiliates on the Balance
        Sheets.

5.       RATE MATTERS

        FERC

            As  discussed  in  Note 3 of the  Notes  to  Consolidated  Financial
      Statements of the 1999 Annual  Report,  the AEP System  companies  filed a
      settlement  agreement  for Federal  Energy  Regulatory  Commission  (FERC)
      approval related to an open access transmission tariff. The Company made a
      provision in 1999 for an agreed to refund including interest.

            On March 16, 2000, the FERC approved the settlement  agreement filed
      in December  1999  resolving  the issues on  rehearing  of a July 30, 1999
      order.  Under terms of the  settlement,  AEP is  required to make  refunds
      retroactive to September 7, 1993 to certain customers affected by the July
      30, 1999 FERC order.  The refunds were made in two  payments.  Pursuant to
      FERC orders the first  payment  was made in  February  2000 and the second
      payment was made on August 1, 2000. In addition, a new lower rate of $1.55
      kw/month was made effective January 1, 2000, for all transmission  service
      customers and a rate of $1.42 kw/month was  established and took effect on
      June 16, 2000 after the consummation of the AEP and Central and South West
      Corporation merger. Prior to January 1, 2000, the rate was $2.04 kw/month.
      Unless the  Company  and the  market  grow the  volume of  physical  power
      transactions to increase the utilization of the AEP System's  transmission
      lines, the new open access  transmission rate will adversely impact future
      results of operations and cash flows.

            In  connection  with the  merger,  the  Indiana  Utility  Regulatory
      Commission and Michigan  Public  Service  Commission  approved  settlement
      agreements  that,  among  other  things,  provides  for sharing net merger
      savings with customers  over eight years through  reductions to customers'
      bills.  The  terms  of  the  Indiana   settlement  require  reductions  in
      customers' bills of approximately $67 million over eight years.  Under the
      Michigan  settlement,  billing  credits will be used to reduce  customers'
      bills by  approximately  $14 million  over eight years for net  guaranteed
      merger savings.  In the event that actual net merger savings are less than
      the amounts credited to customers'  bills,  results of operations and cash
      flows will be adversely affected.

6.    FACTORING OF RECEIVABLES
      ------------------------

               In June 2000,  Indiana  Michigan  Power  Company  entered  into a
        factoring  arrangement  with an affiliate,  CSW Credit,  Inc. Under this
        arrangement  the Company  sells  without  recourse  its retail  customer
        accounts  receivable and accrued utility revenue  balances to CSW Credit
        and  is  charged  a  fee  based  on  CSW   Credit's   financing   costs,
        uncollectible  accounts  experience  for the Company's  receivables  and
        administrative   costs.  The  costs  of  factoring   customer   accounts
        receivable  is reported as an  operating  expense.  At June 30, 2000 the
        amount of factored accounts  receivable and accrued utility revenues was
        $93.7 million.

7.      CONTINGENCIES

        COLI Litigation

            As  discussed  in  Note 5 of the  Notes  to  Consolidated  Financial
      Statements  in the  1999  Annual  Report,  the  deductibility  of  certain
      interest deductions related to AEP's corporate owned life insurance (COLI)
      program  for  taxable  years  1991  through  1996 is under  review  by the
      Internal Revenue Service (IRS).  Adjustments have been or will be proposed
      by the IRS  disallowing  COLI interest  deductions.  A disallowance of the
      COLI interest  deductions  through June 30, 2000 would reduce  earnings by
      approximately $66 million (including interest).

            The Company made payments of taxes and interest attributable to COLI
      interest  deductions  for  taxable  years 1991  through  1998 to avoid the
      potential  assessment  by the  IRS of any  additional  above  market  rate
      interest on the contested amount.  The payments to the IRS are included on
      the consolidated  balance sheet in other property and investments  pending
      the  resolution  of this  matter.  The Company is seeking  refund  through
      litigation of all amounts paid plus interest.

            In order to resolve this issue,  the Company  filed suit against the
      United States in the U.S. District Court for the Southern District of Ohio
      in 1998. In 1999 a U.S. Tax Court judge decided in the  Winn-Dixie  Stores
      v. Commissioner case that a corporate  taxpayer's COLI interest  deduction
      should  be  disallowed.   Notwithstanding  the  Tax  Court's  decision  in
      Winn-Dixie,  management  has made no provision  for any  possible  adverse
      earnings impact from this matter because it believes, and has been advised
      by outside counsel, that it has a meritorious position and will vigorously
      pursue  its  lawsuit.  In the  event  the  resolution  of this  matter  is
      unfavorable,  it  will  have a  material  adverse  impact  on  results  of
      operations, cash flows and possibly financial condition.

      Federal EPA Complaint and Notice of Violation

            As  discussed  in  Note 5 of the  Notes  to  Consolidated  Financial
      Statements  in the 1999 Annual  Report,  the Company has been  involved in
      litigation regarding generating plant emissions. Notices of Violation were
      issued  and a  complaint  was filed by the U.S.  Environmental  Protection
      Agency (Federal EPA) in the U.S.  District Court that alleges the Company,
      certain affiliates and eleven unaffiliated utilities made modifications to
      generating units at certain of their coal-fired generating plants over the
      course of the past 25 years that extend unit  operating  lives or increase
      unit generating capacity without a preconstruction  permit in violation of
      the  Clean  Air Act.  The  complaint  was  amended  in  March  2000 to add
      allegations for certain generating units previously named in the complaint
      and to include  additional AEP System  generating  units  previously named
      only in the Notices of  Violation  in the  complaint.  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.

            A number of  northeastern  and eastern  states were granted leave to
      intervene in the Federal EPA's action  against the Company under the Clean
      Air Act.  A lawsuit  against  power  plants  owned by  certain  AEP System
      companies  alleging  similar  violations  to  those  in  the  Federal  EPA
      complaint  and  Notices  of  Violation  was filed by a number  of  special
      interest groups and has been consolidated with the Federal EPA action.

            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).  Civil penalties,  if ultimately  imposed by the court,
      and the cost of any required new pollution control equipment, if the court
      accepts Federal EPA's contentions, could be substantial.

            On May 10,  2000,  the  Company  filed  motions  to  dismiss  all or
      portions of the  complaints.  Briefing on these  motions was  completed on
      August  2,  2000.   Management   believes  its  maintenance,   repair  and
      replacement  activities  were in  conformity  with the  Clean  Air Act and
      intends to vigorously pursue its defense of this matter.

            In the event the Company does 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 or future  market  prices for
      energy if generation is deregulated.

      NOx Reductions

                      As  discussed  in  Note 6 of  the  Notes  to  Consolidated
        Financial Statements in the 1999 Annual Report, Federal EPA had issued a
        final  rule (the NOx  rule)  that  requires  substantial  reductions  in
        nitrogen oxide (NOx) emissions in 22 eastern states,  including  certain
        states in which the AEP System's generating plants are located. A number
        of  utilities,   including  certain  AEP  System  companies,  had  filed
        petitions  seeking  a review  of the  final  rule in the  U.S.  Court of
        Appeals for the District of Columbia  Circuit  (Appeals  Court).  In May
        1999, the Appeals Court indefinitely  stayed the requirement that states
        develop  revised air quality  programs to impose the NOx  reductions but
        did not,  however,  stay the final  compliance  date of May 1, 2003.  In
        March 2000 the Appeals Court issued a decision  generally  upholding the
        NOx rule.  On April 20,  2000,  certain AEP System  companies  and other
        petitioners  filed for rehearing of this decision  including a rehearing
        by the entire Appeals Court.  On June 22, 2000, the Appeals Court denied
        the  petition for  rehearing  and lifted the stay related to the states'
        development   of  revised  air  quality   programs  to  impose  the  NOx
        reductions. The petition for a rehearing before the entire Appeals Court
        was also denied.  The AEP System companies  subject to the NOx rule plan
        to appeal to the U.S. Supreme Court.

               Preliminary  estimates indicate that compliance with the NOx rule
        upheld  by  the  Appeals   Court  could   result  in  required   capital
        expenditures  of  approximately  $202  million  for the  Company.  Since
        compliance costs cannot be estimated with certainty, the actual costs to
        comply could be significantly  different than the Company's  preliminary
        estimate depending upon the compliance  alternatives selected to achieve
        reductions  in NOx  emissions.  Unless  such  costs are  recovered  from
        customers  through  regulated  rates  and/or  future  market  prices for
        electricity  if  generation  is  deregulated,  they will have an adverse
        effect  on  future  results  of  operations,  cash  flows  and  possibly
        financial condition.

        Other

               The Company  continues to be involved in other matters  discussed
in its 1999 Annual Report.


<PAGE>





                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                             AND FINANCIAL CONDITION

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
                     ---------------------------------------

RESULTS OF OPERATIONS

        The Company  reported a loss of $39  million  for the second  quarter of
2000  compared with net income of $10 million in 1999 and a $76 million loss for
the year-to-date period compared to net income of $30 million in 1999. Increased
operating and  maintenance  expenses to prepare the Company's two unit Donald C.
Cook Nuclear Plant (Cook Plant) for restart  following an extended outage is the
primary reason for the earnings  decline.  An extended  outage of the Cook Plant
began in  September  1997  when both  nuclear  generating  units  were shut down
because of questions regarding the operability of certain safety systems. Unit 2
returned to service in June 2000 and  achieved  full power  operation on July 5,
2000. In accordance  with settlement  agreements in Indiana and Michigan,  which
resolved all jurisdictional  rate-related  issues applicable to the Cook Plant's
extended outage, certain restart expenses were deferred in 1999. The settlements
in the  Indiana  and  Michigan  jurisdictions  were  approved  in March 1999 and
December 1999, respectively, retroactive to January 1, 1999. These deferrals are
being amortized on a straight-line basis through December 31, 2003.

   Income statement line items which changed significantly were:

                                     Increase (Decrease)

                        Second Quarter            Year-to-Date

                        (in millions)     %   (in millions)    %
                        --------------    -   -------------    -

Operating Revenues          $ 26          8       $ 36         5
Fuel                           2          4          8         9
Purchased Power               29         43         52        40
Other Operation               36         31         78        38
Maintenance                   31         127         55        99
Federal Income Taxes         (27)       N.M.       (57)      N.M.
Interest Charges               4         24          6        15

N.M. = Not Meaningful

         The increase in operating revenues resulted from increased sales to the
American  Electric Power System Power Pool (AEP Power Pool) and increased  sales
and forward trades to neighboring utility systems and power marketers by the AEP
Power  Pool on behalf of the  Company.  As a member of the AEP Power  Pool,  the
Company shares in the revenues and costs of the AEP Power Pool's wholesale sales
and forward  trades.  The Company's  share of these AEP Power Pool  transactions
within  the AEP System  traditional  marketing  area  (within  two  transmission
systems  of AEP  System)  are  recorded  as  operating  revenues  and  purchases
accounting for the increases in revenues and purchased  power  expense.  Forward
trading sales and  purchases are recorded on a net basis in operating  revenues.
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.  As a result of the Company's  obligation to purchase  power from an
affiliated  company,  the Company was required to purchase  additional energy in
2000 due to the expiration of that  affiliate's  agreement to supply power to an
unaffiliated  utility.  The Company,  therefore,  was able to deliver additional
power to the AEP Power  Pool,  accounting  for the  increase in sales to the AEP
Power Pool and operating  revenues.  The increase in operating revenues was also
due to a significant increase in AEP Power Pool transactions which resulted from
an affiliated  company's major industrial  customer's decision not to extend its
purchase power agreement which provided  additional  power to the AEP Power Pool
allowing the Power Pool to increase its wholesale sales.

         Fuel expense increased for the year-to-date  period due to a 12.5% rise
in generation  reflecting  increased  availability  of the Company's  generating
units as a result of shorter planned maintenance outages.

        The increases in other operation and maintenance expenses were primarily
caused by the  expenses  of  continuing  work to restart  the Cook Plant and the
effect of deferring restart expenditures in 1999 under the terms of the approved
settlement agreement in Indiana.

         The decrease in federal income tax expense  attributable  to operations
was primarily due to a decrease in pre-tax operating income.

         Interest  charges  increased as a result of  additional  long-term  and
short-term borrowings mainly to fund the restart expenditures.

        Financial Condition

         Total plant and property  additions  including  capital  leases for the
         year-to-date  period were $108 million.  During the first six months of
         2000 the Company retired $48 million  principal amount of long-term and
         decreased short-term

debt by $224 million from year-end  balances.  The Company has in the past,  and
may in the future,  acquire  outstanding  debt and preferred stock securities in
open market transactions.

         During the second  quarter the AEP System  established  a Money Pool to
coordinate short-term borrowings for certain of its subsidiaries,  primarily the
U.S. domestic electric utility operating  companies,  including the Company. The
operation of the Money Pool is designed to match on a daily basis the  available
cash and borrowing requirements of the participants, thereby minimizing the need
for  borrowings  from  external  sources.   The  daily  cash  positions  of  the
participants  are netted and if there is a  deficiency  in cash,  the Money Pool
raises  funds  through  external  borrowing.  If there is a net  excess in cash,
existing  external  borrowings  are paid  down,  or,  if there  are no  external
borrowings maturing, the excess funds are invested.

     CSW Credit,  Inc., a subsidiary of AEP, factors electric  customer accounts
receivable for affiliated  operating companies and unaffiliated  companies.  CSW
Credit,  Inc.  issues  commercial  paper  on a stand  alone  basis  and does not
participate  in the Money Pool. In June 2000 the factoring of customer  accounts
receivable  for  affiliated  companies was expanded as a result of the merger to
include the Company.

         The  shutdown  of the Cook Units and the  related  costs to restart the
Units have  contributed to the reduction in the Company's  retained  earnings at
June 30, 2000 to $61 million.  Unless  approval is received from the  Securities
and Exchange  Commission  (SEC) under the Public Utility  Holding Company Act of
1935 and the Federal Energy Regulatory Commission (FERC) under the Federal Power
Act, the Company can only pay dividends on its outstanding  common stock held by
its  parent  American  Electric  Power  Company,   Inc.  and  dividends  on  its
outstanding  Preferred  Stock out of retained  earnings.  To the extent that the
Company  has  insufficient  retained  earnings to make such  preferred  dividend
payments in the future,  the Company intends to request SEC and FERC approval to
make preferred dividend payments out of capital surplus,  which was $733 million
at June 30, 2000. Any failure to obtain such  approvals  would restrict for some
period of time the  ability of the  Company to  continue  to make such  dividend
payments.  Mortgage  indentures,  charter  provisions  and orders of  regulatory
authorities  place various  restrictions on the use of retained earnings for the
payment of cash  dividends on the Company's  common stock.  As of June 30, 2000,
$5.9 million of retained earnings were restricted. Cook Nuclear Plant Shutdown

      As discussed in Note 2 of the Notes to Consolidated  Financial  Statements
in the 1999 Annual  Report,  the Cook  Nuclear  Plant was shut down in September
1997 due to questions  regarding the  operability of certain safety systems that
arose during a Nuclear  Regulatory  Commission  (NRC) architect  engineer design
inspection. Cook Plant is a two-unit, 2,110 megawatt plant.

      On July 5, 2000,  Cook Nuclear  Plant Unit 2, the first unit  scheduled to
restart, reached 100% power completing its restart process.

      On July 26, 2000,  the Company  announced that the restart of Cook Nuclear
Plant Unit 1 would cost an additional $145 million and was scheduled to occur in
the first quarter of 2001.  Unforeseen  issues or  difficulties  encountered  in
preparing Unit 1 for restart could potentially delay its return to service.

      Expenditures  to  restart  the  Cook  units  had been  estimated  to total
approximately  $574  million.  The  additional  $145  million  raises  the total
estimate to $719  million.  Through June 30, 2000,  $534 million has been spent.
For the six months ended June 30, 2000,  restart costs of $181 million have been
recorded in other operation and maintenance expense,  including  amortization of
$20 million of restart costs  previously  deferred in accordance with settlement
agreements in the Indiana and Michigan retail  jurisdictions.  At June 30, 2000,
deferred restart costs of $140 million are included in regulatory assets.

      The costs of the extended  outage and restart efforts will have a material
adverse  effect  on future  results  of  operations,  cash  flows  and  possibly
financial  condition  until the second unit is restarted.  The  amortization  of
restart costs deferred under Indiana and Michigan retail jurisdiction settlement
agreements  will adversely  effect  results of operations  through 2003 when the
amortization  period ends. The annual amortization of the restart cost deferrals
is $40 million.  Management  believes that Unit 1 of the Cook Plant will also be
successfully returned to service.  However, if for some unknown reason it is not
returned to service or its return is delayed significantly it would have an even
greater material adverse effect on future results of operations,  cash flows and
financial condition.

Litigation

      As discussed in Note 5 of the Notes to Consolidated  Financial  Statements
in the 1999 Annual Report,  the  deductibility  of certain  interest  deductions
related to AEP's corporate owned life insurance (COLI) program for taxable years
1991  through  1996 is under  review  by the  Internal  Revenue  Service  (IRS).
Adjustments  have been or will be proposed by the IRS disallowing  COLI interest
deductions. A disallowance of the COLI interest deductions through June 30, 2000
would reduce earnings by approximately $66 million (including interest).

      The Company  made  payments  of taxes and  interest  attributable  to COLI
interest  deductions  for taxable years 1991 through 1998 to avoid the potential
assessment  by the IRS of any  additional  above  market  rate  interest  on the
contested  amount.  The  payments to the IRS are  included  on the  consolidated
balance sheet in other property and  investments  pending the resolution of this
matter.  The Company is seeking  refund  through  litigation of all amounts paid
plus interest.

      In order to resolve this issue,  the Company filed suit against the United
States in the U.S.  District Court for the Southern District of Ohio in 1998. In
1999 a U.S. Tax Court judge  decided in the  Winn-Dixie  Stores v.  Commissioner
case that a corporate  taxpayer's COLI interest  deduction should be disallowed.
Notwithstanding  the Tax Court?s decision in Winn-Dixie,  management has made no
provision for any possible  adverse  earnings impact from this matter because it
believes,  and has been advised by outside  counsel,  that it has a  meritorious
position and will vigorously pursue its lawsuit.  In the event the resolution of
this matter is unfavorable, it will have a material adverse impact on results of
operations,  cash flows and possibly financial condition.  Federal EPA Complaint
and Notice of Violation

      As discussed in Note 5 of the Notes to Consolidated  Financial  Statements
in the 1999 Annual Report, the Company has been involved in litigation regarding
generating plant emissions. Notices of Violation were issued and a complaint was
filed by the U.S.  Environmental  Protection  Agency  (Federal  EPA) in the U.S.
District  Court  that  alleges  the  Company,   certain  affiliates  and  eleven
unaffiliated  utilities  made  modifications  to generating  units at certain of
their  coal-fired  generating  plants  over the course of the past 25 years that
extend unit  operating  lives or increase  unit  generating  capacity  without a
preconstruction  permit in  violation of the Clean Air Act.  The  complaint  was
amended in March 2000 to add allegations for certain generating units previously
named in the complaint and to include  additional  AEP System  generating  units
previously  named only in the Notices of Violation in the  complaint.  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.

      A  number  of  northeastern  and  eastern  states  were  granted  leave to
intervene in the Federal  EPA's action  against the Company  under the Clean Air
Act.  A lawsuit  against  power  plants  owned by certain  AEP System  companies
alleging similar violations to those in the Federal EPA complaint and Notices of
Violation  was  filed  by a  number  of  special  interest  groups  and has been
consolidated with the Federal EPA action.

      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).
Civil  penalties,  if  ultimately  imposed  by the  court,  and the  cost of any
required new pollution  control  equipment,  if the court accepts  Federal EPA's
contentions, could be substantial.

      On May 10, 2000,  the Company  filed motions to dismiss all or portions of
the  complaints.  Briefing  on these  motions was  completed  on August 2, 2000.
Management believes its maintenance,  repair and replacement  activities were in
conformity  with the Clean Air Act and intends to vigorously  pursue its defense
of this matter.

      In the event the Company does 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 or future  market  prices for energy if  generation is
deregulated. NOx Reductions

        As discussed in Note 6 of the Notes to Consolidated Financial Statements
in the 1999  Annual  Report,  Federal EPA had issued a final rule (the NOx rule)
that requires  substantial  reductions in nitrogen  oxide (NOx)  emissions in 22
eastern states,  including  certain states in which the AEP System's  generating
plants  are  located.  A number  of  utilities,  including  certain  AEP  System
companies,  had filed  petitions  seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit  (Appeals  Court).  In May
1999, the Appeals Court indefinitely  stayed the requirement that states develop
revised air quality programs to impose the NOx reductions but did not,  however,
stay the final  compliance  date of May 1, 2003. In March 2000 the Appeals Court
issued a decision  generally  upholding the NOx rule. On April 20, 2000, certain
AEP System companies and other  petitioners filed for rehearing of this decision
including a rehearing by the entire Appeals Court. On June 22, 2000, the Appeals
Court  denied the  petition  for  rehearing  and lifted the stay  related to the
states'   development  of  revised  air  quality  programs  to  impose  the  NOx
reductions.  The petition for a rehearing  before the entire  Appeals  Court was
also denied.  The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.

        Preliminary  estimates indicate that compliance with the NOx rule upheld
by  the  Appeals  Court  could  result  in  required  capital   expenditures  of
approximately  $202 million for the Company.  Since  compliance  costs cannot be
estimated  with  certainty,  the actual costs to comply  could be  significantly
different than the Company's  preliminary estimate depending upon the compliance
alternatives selected to achieve reductions in NOx emissions.  Unless such costs
are recovered from customers through regulated rates and/or future market prices
for electricity if generation is  deregulated,  they will have an adverse effect
on future results of operations, cash flows and possibly financial condition.

Market Risks

        The Company has certain market risks inherent in its business activities
from changes in electricity  commodity  prices and interest  rates.  Market risk
represents  the risk of loss that may impact the Company due to adverse  changes
in commodity market prices and interest rates. The Company's  exposure to market
risk  from  the  trading  of  electricity  and  related   financial   derivative
instruments,  which are allocated to the Company  through the American  Electric
Power  System  Power  Pool,  were less than $5 million  at June 30,  2000 and $3
million at December 31, 1999 based on the use of a risk measurement  model which
calculates  Value at Risk (VaR).  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 three-day holding period.

        The exposure to changes in interest rates from the Company's  short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.


<PAGE>
<TABLE>
<CAPTION>


                             KENTUCKY POWER COMPANY

                              STATEMENTS OF INCOME

                                   (UNAUDITED)

                                           Three Months Ended        Six Months Ended

                                                 June 30,                 June 30,
                                           -------------------     ---------------
                                             2000        1999        2000         1999
                                             ----        ----        ----         ----
                                                          (in thousands)

<S>                                        <C>         <C>         <C>          <C>
OPERATING REVENUES . . . . . . . . . . . . $97,759     $86,231     $194,963     $176,972
                                           -------     -------     --------     --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . .  17,871      22,284       34,673       41,975
  Purchased Power. . . . . . . . . . . . .  38,752      25,920       72,234       50,347
  Other Operation. . . . . . . . . . . . .  12,103      11,768       22,487       24,119
  Maintenance. . . . . . . . . . . . . . .   8,438       5,047       14,805        9,838
  Depreciation and Amortization. . . . . .   7,676       7,287       15,279       14,477
  Taxes Other Than Federal Income Taxes. .   2,659       2,682        5,493        5,216
  Federal Income Taxes . . . . . . . . . .     804       1,010        4,979        5,407
                                           -------    --------     --------     --------

         TOTAL OPERATING EXPENSES. . . . .  88,303      75,998      169,950      151,379
                                           -------     -------     --------     --------

OPERATING INCOME . . . . . . . . . . . . .   9,456      10,233       25,013       25,593

NONOPERATING INCOME (LOSS) . . . . . . . .     671         (41)         625         (155)
                                           -------     -------     --------     --------

INCOME BEFORE INTEREST CHARGES . . . . . .  10,127      10,192       25,638       25,438

INTEREST CHARGES . . . . . . . . . . . . .   7,678       7,197       15,137       14,234
                                           -------     -------     --------     --------

NET INCOME . . . . . . . . . . . . . . . . $ 2,449     $ 2,995     $ 10,501     $ 11,204
                                           =======     =======     ========     ========




                         STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                                           Three Months Ended        Six Months Ended

                                                 June 30,                 June 30,
                                           -------------------     ---------------
                                             2000        1999        2000         1999
                                             ----        ----        ----         ----
                                                          (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . $67,572     $72,218      $67,110      $71,452

NET INCOME . . . . . . . . . . . . . . . .   2,449       2,995       10,501       11,204

CASH DIVIDENDS DECLARED. . . . . . . . . .   7,590       7,443       15,180       14,886
                                           -------     -------      -------      -------

BALANCE AT END OF PERIOD . . . . . . . . . $62,431     $67,770      $62,431      $67,770
                                           =======     =======      =======      =======



The common  stock of the  Company is wholly  owned by  American  Electric  Power
Company, Inc.

See Notes to Financial Statements.

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


                             KENTUCKY POWER COMPANY

                                 BALANCE SHEETS

                                   (UNAUDITED)

                                                          June 30,        December 31,
                                                            2000              1999
                                                         ----------       --------
                                                                (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                      <C>               <C>
  Production . . . . . . . . . . . . . . . . . . . . .   $  270,799        $  268,618
  Transmission . . . . . . . . . . . . . . . . . . . .      357,252           355,442
  Distribution . . . . . . . . . . . . . . . . . . . .      379,830           372,752
  General. . . . . . . . . . . . . . . . . . . . . . .       66,767            67,608
  Construction Work in Progress. . . . . . . . . . . .       11,197            14,628
                                                         ----------        ----------
          Total Electric Utility Plant . . . . . . . .    1,085,845         1,079,048
  Accumulated Depreciation and Amortization. . . . . .      347,386           340,008
                                                         ----------        ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      738,459           739,040
                                                         ----------        ----------


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .       51,805            20,416
                                                         ----------        ----------


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          692               674
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .        2,412            18,952
    Affiliated Companies . . . . . . . . . . . . . . .       20,156            15,223
    Miscellaneous. . . . . . . . . . . . . . . . . . .        4,626             8,343
    Allowance for Uncollectible Accounts . . . . . . .         (261)             (637)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .       11,045            10,441
  Materials and Supplies . . . . . . . . . . . . . . .       17,167            18,113
  Accrued Utility Revenues . . . . . . . . . . . . . .         -               13,737
  Energy Trading Contracts . . . . . . . . . . . . . .      234,409            33,919
  Prepayments. . . . . . . . . . . . . . . . . . . . .          998             1,450
                                                         ----------        ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . .      291,244           120,215
                                                         ----------        ----------


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .      101,216            96,296
                                                         ----------        ----------


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .        8,480            10,671
                                                         ----------        ----------


            TOTAL. . . . . . . . . . . . . . . . . . .   $1,191,204        $  986,638
                                                         ==========        ==========

See Notes to Financial Statements.

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


                             KENTUCKY POWER COMPANY

                                 BALANCE SHEETS

                                   (UNAUDITED)

                                                           June 30,       December 31,
                                                             2000             1999
                                                          ----------      --------
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $50 Par Value:
    Authorized -  2,000,000 Shares

<S>                                                       <C>               <C>
    Outstanding - 1,009,000 Shares . . . . . . . . . .    $   50,450        $ 50,450
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       158,750         158,750
  Retained Earnings. . . . . . . . . . . . . . . . . .        62,431          67,110
                                                          ----------        --------
          Total Common Shareholder's Equity. . . . . .       271,631         276,310
  Long-term Debt . . . . . . . . . . . . . . . . . . .       200,921         260,782
                                                          ----------        --------

          TOTAL CAPITALIZATION . . . . . . . . . . . .       472,552         537,092
                                                          ----------        --------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        22,404          23,797
                                                          ----------        --------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .       140,000         105,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .          -             39,665
  Advances from Affiliates . . . . . . . . . . . . . .        43,634            -
  Accounts Payable - General . . . . . . . . . . . . .         7,004           9,923
  Accounts Payable - Affiliated Companies. . . . . . .        23,438          19,743
  Customer Deposits. . . . . . . . . . . . . . . . . .         4,234           4,143
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         5,856           9,860
  Interest Accrued . . . . . . . . . . . . . . . . . .         4,814           4,843
  Energy Trading Contracts . . . . . . . . . . . . . .       231,332          33,094
  Other. . . . . . . . . . . . . . . . . . . . . . . .        10,936          12,020
                                                          ----------        --------

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       471,248         238,291
                                                          ----------        --------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       167,493         165,007
                                                          ----------        --------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        12,312          12,908
                                                          ----------        --------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        45,195           9,543
                                                          ----------        --------

CONTINGENCIES (Note 6)

            TOTAL. . . . . . . . . . . . . . . . . . .    $1,191,204        $986,638
                                                          ==========        ========

See Notes to Financial Statements.

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


                             KENTUCKY POWER COMPANY

                            STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                 Six Months Ended

                                    June 30,

                                                                2000          1999
                                                                ----          ----
                                                                  (in thousands)

OPERATING ACTIVITIES:
<S>                                                           <C>           <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 10,501      $ 11,204
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    15,279        14,480
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     2,563           912
    Deferred Investment Tax Credits. . . . . . . . . . . . .      (596)         (601)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    14,948           442
    Accrued Utility Revenues . . . . . . . . . . . . . . . .    13,737           508
    Fuel, Materials and Supplies . . . . . . . . . . . . . .       342        (4,388)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .       776        (1,202)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (4,004)        1,988
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .    (3,129)        1,258
                                                              --------      --------
        Net Cash Flows From Operating Activities . . . . . .    50,417        24,601
                                                              --------      --------

INVESTING ACTIVITIES - Construction Expenditures . . . . . .   (14,188)      (17,402)
                                                              --------      --------

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .      -           10,000
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (25,000)      (37,812)
  Change in Short-term Debt (net). . . . . . . . . . . . . .   (39,665)       36,000
  Change in Advances from Affiliates (net) . . . . . . . . .    43,634          -
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .   (15,180)      (14,886)
                                                              --------      --------
        Net Cash Flows Used For Financing Activities . . . .   (36,211)       (6,698)
                                                              --------      --------

Net Increase in Cash and Cash Equivalents. . . . . . . . . .        18           501
Cash and Cash Equivalents at Beginning of Period . . . . . .       674         1,935
                                                              --------      --------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $    692      $  2,436
                                                              ========      ========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $15,046,000  and
  $14,748,000  and for income taxes was  $5,921,000  and  $3,631,000 in 2000 and
  1999, respectively.  Noncash acquisitions under capital leases were $1,836,000
  and $1,150,000 in 2000 and 1999, respectively.

See Notes to Financial Statements.

</TABLE>
<PAGE>





                             KENTUCKY POWER COMPANY
                          NOTES TO FINANCIAL STATEMENTS
                                  JUNE 30, 2000

                                   (UNAUDITED)

1.      GENERAL

               The accompanying unaudited financial statements should be read in
        conjunction  with the 1999 Annual  Report as  incorporated  in and filed
        with  the  Form  10-K.  In the  opinion  of  management,  the  financial
        statements reflect all adjustments  (consisting of only normal recurring
        accruals) which are necessary for a fair  presentation of the results of
        operations for interim periods.

2.      FINANCING ACTIVITIES

               In April 2000 the Company  redeemed a $25 million  term loan note
        with a rate  of  6.57%.  The  Company  has in the  past,  and may in the
        future,  acquire outstanding debt and preferred stock securities in open
        market transactions.

3.      MONEY POOL

             On June 15, 2000,  the Company became a participant in the American
        Electric Power (AEP) System Money Pool (Money Pool). The Money Pool is a
        mechanism  structured to meet the short-term  cash  requirements  of the
        participants  with AEP Company,  Inc. acting as the primary  borrower on
        behalf  of the  Money  Pool.  The  Company's  affiliates  that  are U.S.
        domestic   electric   utility   operating   companies  are  the  primary
        participants in the Money Pool.

             The  operation  of the Money Pool is  designed  to match on a daily
        basis the available cash and borrowing requirements of the participants.
        Participants  with excess cash loan funds to the Money Pool reducing the
        amount of external  funds AEP Company,  Inc. needs to borrow to meet the
        short-term cash  requirements of other  participants  with advances from
        the Money Pool.  AEP Company,  Inc.  borrows the funds needed on a daily
        basis to meet the net cash requirements of the Money Pool  participants.
        A weighted  average daily interest rate which is calculated based on the
        outstanding  short-term  debt  borrowings  made by AEP Company,  Inc. is
        applied to each Money Pool participant's daily outstanding investment or
        debt position to determine interest income or interest expense. Interest
        income is included  in  nonoperating  income,  and  interest  expense is
        included  in  interest  charges.  As a result of  becoming  a Money Pool
        participant,  the Company  retired its  short-term  debt and reports its
        borrowing from the Money Pool as Advances from Affiliates on the Balance
        Sheets.


<PAGE>


4.      RATE MATTERS

        FERC

            As discussed in Note 3 of the Notes to Financial  Statements  of the
      1999 Annual Report, the AEP System companies filed a settlement  agreement
      for Federal Energy  Regulatory  Commission  (FERC) approval  related to an
      open access transmission  tariff. The Company made a provision in 1999 for
      an agreed to refund including interest under the settlement agreement.

            On March 16, 2000, the FERC approved the settlement  agreement filed
      in December  1999  resolving  the issues on  rehearing  of a July 30, 1999
      order.  Under terms of the  settlement,  AEP is  required to make  refunds
      retroactive to September 7, 1993 to certain customers affected by the July
      30, 1999 FERC order.  The refunds were made in two  payments.  Pursuant to
      FERC orders the first  payment  was made in  February  2000 and the second
      payment was made on August 1, 2000. In addition, a new lower rate of $1.55
      kw/month was made effective January 1, 2000, for all transmission  service
      customers and a rate of $1.42 kw/month was  established and took effect on
      June 16, 2000 after the consummation of the AEP and Central and South West
      Corporation merger. Prior to January 1, 2000, the rate was $2.04 kw/month.
      Unless the  Company  and the  market  grow the  volume of  physical  power
      transactions  to increase  utilization  of the AEP  System's  transmission
      lines, the new open access  transmission rate will adversely impact future
      results of operations and cash flows.

      Kentucky

            In  connection   with  the  merger,   the  Kentucky  Public  Service
      Commission  approved a  settlement  agreement  that,  among other  things,
      provides for sharing net merger savings with Kentucky customers over eight
      years  through  reductions to customers'  bills.  The Kentucky  customers'
      share of the net  merger  savings  is  expected  to be  approximately  $28
      million.  In the event that  actual net merger  savings  are less than the
      amounts credited to customers' bills, results of operations and cash flows
      will be adversely affected.

5.       FACTORING OF RECEIVABLES

               In June 2000,  Kentucky  Power  Company  entered into a factoring
        arrangement with an affiliate,  CSW Credit,  Inc. Under this arrangement
        the  Company  sells  without  recourse  its  retail  customer   accounts
        receivable  and accrued  utility  revenue  balances to CSW Credit and is
        charged  a fee  based on CSW  Credit's  financing  costs,  uncollectible
        accounts  experience for the Company's  receivables  and  administrative
        costs. The costs of factoring  customer accounts  receivable is reported
        as an  operating  expense.  At June 30,  2000  the  amount  of  factored
        accounts receivable and accrued utility revenues was $28.1 million.

6.       CONTINGENCIES

        COLI Litigation

               As discussed in Note 4 of the Notes to  Financial  Statements  in
        the 1999 Annual Report, the deductibility of certain interest deductions
        related to AEP's  corporate  owned life  insurance  (COLI)  program  for
        taxable years 1992 through 1996 is under review by the Internal  Revenue
        Service  (IRS).  Adjustments  have been or will be  proposed  by the IRS
        disallowing  COLI  interest  deductions.  A  disallowance  of  the  COLI
        interest  deductions  through  June 30,  2000 would  reduce  earnings by
        approximately $8 million (including interest).

        The Company  made  payments of taxes and interest  attributable  to COLI
        interest  deductions  for taxable  years 1992  through 1998 to avoid the
        potential  assessment  by the IRS of any  additional  above  market rate
        interest on the contested  amount.  The payments to the IRS are included
        on the  balance  sheet in other  property  and  investments  pending the
        resolution of this matter.  The Company is seeking refund of all amounts
        paid plus interest.

        In order to resolve this issue, AEP Company, Inc. filed suit against the
        United States in the U.S.  District  Court for the Southern  District of
        Ohio in 1998. In 1999 a U.S. Tax Court judge  decided in the  Winn-Dixie
        Stores v.  Commissioner  case that a corporate  taxpayer's COLI interest
        deduction should be disallowed. Notwithstanding the Tax Court's decision
        in Winn-Dixie, management has made no provision for any possible adverse
        earnings  impact  from this  matter  because it  believes,  and has been
        advised by outside counsel,  that it has a meritorious position and will
        vigorously  pursue  its  lawsuit.  In the event the  resolution  of this
        matter is unfavorable, it will have a material adverse impact on results
        of operations and cash flows.

        Federal EPA Complaint and Notice of Violation

        As discussed in Note 4 of the Notes to Financial  Statements in the 1999
        Annual  Report,  the Company has been involved in  litigation  regarding
        generating  plant  emissions.  Notices of  Violation  were  issued and a
        complaint was filed by the U.S. Environmental Protection Agency (Federal
        EPA)  in the  U.S.  District  Court  that  alleges  certain  AEP  System
        companies  and  eleven  unaffiliated  utilities  made  modifications  to
        generating units at certain of their coal-fired  generating  plants over
        the  course of the past 25 years that  extend  unit  operating  lives or
        increase unit generating  capacity without a  preconstruction  permit in
        violation of the Clean Air Act. The  complaint was amended in March 2000
        to add allegations for certain  generating units previously named in the
        complaint  and  to  include   additional  AEP  System  generating  units
        previously  named only in the  Notices of  Violation  in the  complaint.
        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.

            A number of  northeastern  and eastern  states were granted leave to
      intervene in the Federal EPA's action  against the Company under the Clean
      Air Act. A lawsuit  against  power  plants  owned by AEP System  companies
      alleging  similar  violations  to those in the Federal EPA  complaint  and
      Notices of Violation was filed by a number of special  interest groups and
      has been consolidated with the Federal EPA action.

            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).  Civil penalties,  if ultimately  imposed by the court,
      and the cost of any required new pollution control equipment, if the court
      accepts Federal EPA's contentions, could be substantial.

            On May 10,  2000,  the  Company  filed  motions  to  dismiss  all or
      portions of the  complaints.  Briefing on these  motions was  completed on
      August  2,  2000.   Management   believes  its  maintenance,   repair  and
      replacement  activities  were in  conformity  with the  Clean  Air Act and
      intends to vigorously pursue its defense of this matter.

            In the event the Company does 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.

      NOx Reductions

               As discussed in Note 6 of the Notes to  Financial  Statements  in
        the 1999  Annual  Report,  Federal  EPA had issued a final rule (the NOx
        rule) that  requires  substantial  reductions  in  nitrogen  oxide (NOx)
        emissions in 22 eastern  states,  including  certain states in which the
        AEP  System's  generating  plants are  located.  A number of  utilities,
        including  certain AEP System  companies,  had filed petitions seeking a
        review of the final rule in the U.S.  Court of Appeals for the  District
        of Columbia  Circuit  (Appeals  Court).  In May 1999,  the Appeals Court
        indefinitely  stayed the  requirement  that states  develop  revised air
        quality programs to impose the NOx reductions but did not, however, stay
        the final  compliance  date of May 1, 2003.  In March  2000 the  Appeals
        Court issued a decision  generally  upholding the NOx rule. On April 20,
        2000,  certain  AEP System  companies  and other  petitioners  filed for
        rehearing of this decision  including a rehearing by the entire  Appeals
        Court.  On June 22,  2000,  the Appeals  Court  denied the  petition for
        rehearing  and lifted the stay  related to the  states'  development  of
        revised air quality programs to impose the NOx reductions.  The petition
        for a rehearing before the entire Appeals Court was also denied. The AEP
        System  companies  subject  to the NOx rule  plan to  appeal to the U.S.
        Supreme Court.

               Preliminary  estimates indicate that compliance with the NOx rule
        upheld  by  the  Appeals   Court  could   result  in  required   capital
        expenditures  of  approximately  $106  million  for the  Company.  Since
        compliance costs cannot be estimated with certainty,  the actual cost to
        comply could be significantly  different than the Company's  preliminary
        estimate depending upon the compliance  alternatives selected to achieve
        reductions  in NOx  emissions.  Unless  such  costs are  recovered  from
        customers  through  regulated rates, they will have an adverse effect on
        future  results  of  operations,   cash  flows  and  possibly  financial
        condition.

        Other

               The Company  continues  to be involved in certain  other  matters
discussed in its 1999 Annual Report.


<PAGE>


                             KENTUCKY POWER COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
                     ---------------------------------------

        Although  revenues  rose 13% in the  quarter and 10%  year-to-date,  net
income declined by $0.5 million or 18% and $0.7 million or 6%, respectively,  as
increases in operating expense and interest expense offset the revenue increase.
Income statement line items which changed significantly were:

                                     Increase(Decrease)

                            Second Quarter     Year-to-Date

                            (in millions)   %  (in millions)  %

Operating Revenues . . . . .    $11.5      13     $18.0      10
Fuel Expense . . . . . . . .     (4.4)    (20)     (7.3)    (17)
Purchased Power Expense. . .     12.8      50      21.9      43
Other Operation Expense. . .      0.3       3      (1.6)     (7)
Maintenance Expense. . . . .      3.4      67       5.0      50
Depreciation . . . . . . . .      0.4       5       0.8       6
Interest Charges . . . . . .      0.5       7       0.9       6
Nonoperating Income. . . . .      0.7     N.M.      0.8     N.M.

N.M. = Not Meaningful

        The increases in operating  revenues and purchased power expense are due
to a  significant  increase in American  Electric  Power  System Power Pool (AEP
Power Pool)  transactions  and  affiliated  power  purchases  under a unit power
agreement.  The Company as a member of the AEP Power Pool shares in the revenues
and  costs of the AEP  Power  Pool's  wholesale  sales  and  forward  trades  to
neighboring  utility systems and power  marketers.  The Company's share of these
AEP Power Pool  transactions  within the AEP System  traditional  marketing area
(within  two  transmission  systems of AEP System)  are  recorded  as  operating
revenues and  purchases  accounting  for the increases in revenues and purchased
power expense.  Forward  trading sales and purchases are recorded on a net basis
in operating revenues.  As a result of an affiliated  company's major industrial
customer's  decision not to continue its purchased power  agreement,  additional
power was  available  for AEP Power  Pool  transactions  and  accounted  for the
increase in the Company's  revenue and purchased power expense.  Purchased power
also  increased  due to the  availability  of the Rockport  Plant from which the
Company, under a unit power agreement, purchases 15% of the available power from
the plant. Rockport Plant, which is owned and operated by affiliates,  generated
22% more kwh in the six months ended June 2000 than in the six months ended June
1999.

        Fuel expense  decreased  due a decline in internal  generation.  The Big
Sandy  Plant  Unit 2 began a  planned  outage  on  March  11,  2000  for  boiler
inspections and repairs and returned to service late in April.  Unit 1 started a
planned  outage  April 21,  2000 and  returned to service the second week in May
after completion of boiler inspection and repairs.

        The  Company  as a party to the AEP  Transmission  Agreement  shares the
costs  associated  with the  ownership of the  extra-high  voltage  transmission
system and certain  facilities  at lower  voltages.  Like the AEP Power Pool the
sharing is based upon each  company's  member load ratio  (MLR) and  investment.
Other operation expense decreased for the year-to-date period due to an increase
in  transmission  equalization  credits  as a result of an  increase  in MLR and
increased  investment  in  transmission  plant.  Member load ratio is calculated
monthly on the basis of each AEP Pool members maximum peak demand in relation to
the sum of the maximum peak demands of all five Pool member companies during the
preceding twelve months.

        The outages at Big Sandy caused  maintenance  expense to increase in the
quarter and year-to-date periods.

        The  increase in  transmission  plant  investment  and  improvements  to
distribution facilities caused the increase in depreciation expense.

        Interest charges increased due to an increase in the average outstanding
short-term  debt  balances and an increase in average  short-term  debt interest
rates.

        Nonoperating  income  increased  due to the effect of the  non-regulated
electric  trading outside the AEP Power Pool's  traditional  marketing area. The
AEP Power Pool enters into transactions for the purchase and sale of electricity
options, futures and swaps, and for the forward purchase and sale of electricity
outside of the AEP System's  traditional  marketing area. The Company's share of
these non-regulated trading activities are included in nonoperating income.

Market Risks

        The Company has certain market risks inherent in its business activities
from changes in electricity  commodity  prices and interest  rates.  Market risk
represents  the risk of loss that may impact the Company due to adverse  changes
in commodity market prices and interest rates. The Company's  exposure to market
risk  from  the  trading  of  electricity  and  related   financial   derivative
instruments,  which are allocated to the Company  through the American  Electric
Power  System  Power  Pool,  were less than $2 million  at June 30,  2000 and $1
million at December 31, 1999 based on the use of a risk measurement  model which
calculates  Value at Risk (VaR).  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 three-day holding period.

        The exposure to changes in interest rates from the Company's  short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.


<PAGE>
<TABLE>
<CAPTION>


                       OHIO POWER COMPANY AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                   (UNAUDITED)

                       Three Months Ended Six Months Ended

                                                  June 30,                June 30,
                                            --------------------  ----------------
                                              2000        1999       2000          1999
                                              ----        ----       ----          ----
                                                           (in thousands)

<S>                                         <C>         <C>       <C>           <C>
OPERATING REVENUES . . . . . . . . . . . .  $540,321    $498,587  $1,085,732    $1,016,808
                                            --------    --------  ----------    ----------
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . .   177,314     169,055     392,562       358,218
  Purchased Power. . . . . . . . . . . . .    47,051      35,699      82,353        56,972
  Other Operation. . . . . . . . . . . . .    86,244      82,829     170,696       167,890
  Maintenance. . . . . . . . . . . . . . .    33,595      28,501      61,625        53,991
  Depreciation and Amortization. . . . . .    38,843      37,397      77,332        74,182
  Taxes Other Than Federal Income Taxes. .    41,055      41,952      84,787        85,805
  Federal Income Taxes . . . . . . . . . .    36,251      29,826      71,296        67,466
                                            --------    --------  ----------    ----------
          TOTAL OPERATING EXPENSES . . . .   460,353     425,259     940,651       864,524
                                            --------    --------  ----------    ----------
OPERATING INCOME . . . . . . . . . . . . .    79,968      73,328     145,081       152,284
NONOPERATING INCOME (LOSS) . . . . . . . .     1,250        (492)      4,150         1,508
                                            --------    --------  ----------    ----------
INCOME BEFORE INTEREST CHARGES . . . . . .    81,218      72,836     149,231       153,792
INTEREST CHARGES . . . . . . . . . . . . .    22,985      20,971      44,782        41,106
                                            --------    --------  ----------    ----------
NET INCOME . . . . . . . . . . . . . . . .    58,233      51,865     104,449       112,686
PREFERRED STOCK DIVIDEND REQUIREMENTS. . .       315         367         636           734
                                            --------    --------  ----------    ----------
EARNINGS APPLICABLE TO COMMON STOCK. . . .  $ 57,918    $ 51,498  $  103,813    $  111,952
                                            ========    ========  ==========    ==========



                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                       Three Months Ended Six Months Ended

                                                  June 30,                June 30,
                                            --------------------  ----------------
                                              2000        1999       2000          1999
                                              ----        ----       ----          ----
                                                           (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . .  $595,620    $590,251   $587,424     $587,500
NET INCOME . . . . . . . . . . . . . . . .    58,233      51,865    104,449      112,686
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . .    37,703      57,703     75,406      115,406
    Cumulative Preferred Stock . . . . . .       316         368        633          735
                                            --------    --------   --------     --------

BALANCE AT END OF PERIOD . . . . . . . . .  $615,834    $584,045   $615,834     $584,045
                                            ========    ========   ========     ========

The common  stock of the  Company is wholly  owned by  American  Electric  Power
Company, Inc.

See Notes to Consolidated Financial Statements.

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


                       OHIO POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                               June 30,      December 31,
                                                                 2000            1999
                                                              ----------     --------
                                                                    (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                           <C>             <C>
  Production . . . . . . . . . . . . . . . . . . . . . . . .  $2,736,713      $2,713,421
  Transmission . . . . . . . . . . . . . . . . . . . . . . .     865,548         857,420
  Distribution . . . . . . . . . . . . . . . . . . . . . . .   1,019,733         999,679
  General (including mining assets). . . . . . . . . . . . .     716,380         713,882
  Construction Work in Progress. . . . . . . . . . . . . . .     119,152         116,515
                                                              ----------      ----------
          Total Electric Utility Plant . . . . . . . . . . .   5,457,526       5,400,917
  Accumulated Depreciation and Amortization. . . . . . . . .   2,694,902       2,621,711
                                                              ----------      ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . . . . .   2,762,624       2,779,206
                                                              ----------      ----------



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . .     370,948         253,668
                                                              ----------      ----------



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . . . . .      25,300         157,138
  Advances to Affiliates . . . . . . . . . . . . . . . . . .     148,965            -
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . . . . .     248,834         246,310
    Affiliated Companies . . . . . . . . . . . . . . . . . .     154,502          89,215
    Miscellaneous. . . . . . . . . . . . . . . . . . . . . .      41,319          22,055
    Allowance for Uncollectible Accounts . . . . . . . . . .        (957)         (2,223)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . .      97,933         146,317
  Materials and Supplies . . . . . . . . . . . . . . . . . .      96,671          95,967
  Accrued Utility Revenues . . . . . . . . . . . . . . . . .        -             45,575
  Energy Trading Contracts . . . . . . . . . . . . . . . . .     858,345         134,567
  Prepayments. . . . . . . . . . . . . . . . . . . . . . . .      44,691          38,472
                                                              ----------      ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . . . . .   1,715,603         973,393
                                                              ----------      ----------



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . .     782,102         577,090
                                                              ----------      ----------


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . .      65,565          93,852
                                                              ----------      ----------


            TOTAL. . . . . . . . . . . . . . . . . . . . . .  $5,696,842      $4,677,209
                                                              ==========      ==========


See Notes to Consolidated Financial Statements.

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


                       OHIO POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                                June 30,      December 31,
                                                                  2000            1999
                                                               ----------     --------
                                                                     (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  40,000,000 Shares

<S>                                                            <C>             <C>
    Outstanding - 27,952,473 Shares. . . . . . . . . . . . .   $  321,201      $  321,201
  Paid-in Capital. . . . . . . . . . . . . . . . . . . . . .      462,469         462,376
  Retained Earnings. . . . . . . . . . . . . . . . . . . . .      615,834         587,424
                                                               ----------      ----------
          Total Common Shareholder's Equity. . . . . . . . .    1,399,504       1,371,001
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . . . . .       16,683          16,937
    Subject to Mandatory Redemption. . . . . . . . . . . . .        8,850           8,850
  Long-term Debt . . . . . . . . . . . . . . . . . . . . . .    1,127,612       1,139,834
                                                               ----------      ----------

          TOTAL CAPITALIZATION . . . . . . . . . . . . . . .    2,552,649       2,536,622
                                                               ----------      ----------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . .      406,495         414,837
                                                               ----------      ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . . . . .       87,085          11,677
  Short-term Debt. . . . . . . . . . . . . . . . . . . . . .         -            194,918
  Accounts Payable . . . . . . . . . . . . . . . . . . . . .      374,738         244,982
  Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . .      134,983         179,112
  Interest Accrued . . . . . . . . . . . . . . . . . . . . .       18,197          16,863
  Obligations Under Capital Leases . . . . . . . . . . . . .       34,419          34,284
  Energy Trading Contracts . . . . . . . . . . . . . . . . .      847,076         131,844
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .      109,106          96,445
                                                               ----------      ----------

          TOTAL CURRENT LIABILITIES. . . . . . . . . . . . .    1,605,604         910,125
                                                               ----------      ----------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . .      667,093         676,460
                                                               ----------      ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . .       34,204          35,838
                                                               ----------      ----------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . . .      430,797         103,327
                                                               ----------      ----------

CONTINGENCIES (Note 7)

            TOTAL. . . . . . . . . . . . . . . . . . . . . .   $5,696,842      $4,677,209
                                                               ==========      ==========


See Notes to Consolidated Financial Statements.

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


                       OHIO POWER COMPANY AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                     Six Months Ended

                                                                         June 30,
                                                                 ----------------
                                                                    2000          1999
                                                                    ----          ----
                                                                      (in thousands)
OPERATING ACTIVITIES:
<S>                                                              <C>           <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 104,449     $ 112,686
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . . . .   100,439        93,008
    Deferred Federal Income Taxes. . . . . . . . . . . . . . . .    (6,387)        1,603
    Deferred Fuel Costs (net). . . . . . . . . . . . . . . . . .    (8,844)      (23,695)
    Amortization of Deferred Property Taxes. . . . . . . . . . .    39,944        39,464
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . . . .   (88,341)      (84,397)
    Fuel, Materials and Supplies . . . . . . . . . . . . . . . .    47,680       (55,037)
    Accrued Utility Revenues . . . . . . . . . . . . . . . . . .    45,575        (5,410)
    Prepayments. . . . . . . . . . . . . . . . . . . . . . . . .    (6,219)       (6,881)
    Accounts Payable . . . . . . . . . . . . . . . . . . . . . .   129,756        25,478
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . .   (44,129)        1,170
  Other (net). . . . . . . . . . . . . . . . . . . . . . . . . .     2,443        44,808
                                                                 ---------     ---------
        Net Cash Flows From Operating Activities . . . . . . . .   316,366       142,797
                                                                 ---------     ---------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . . . .   (91,118)      (83,279)
  Proceeds from Sale of Property and Other . . . . . . . . . . .      -              670
                                                                 ---------     ---------
        Net Cash Flows Used For Investing Activities . . . . . .   (91,118)      (82,609)
                                                                 ---------     ---------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . . . .    74,748       148,215
  Change in Short-term Debt (net). . . . . . . . . . . . . . . .  (194,918)       71,085
  Change in Advances to Affiliates (net) . . . . . . . . . . . .  (148,965)         -
  Retirement of Cumulative Preferred Stock . . . . . . . . . . .      (160)         (128)
  Retirement of Long-term Debt . . . . . . . . . . . . . . . . .   (11,752)     (151,223)
  Dividends Paid on Common Stock . . . . . . . . . . . . . . . .   (75,406)     (115,406)
  Dividends Paid on Cumulative Preferred Stock . . . . . . . . .      (633)         (735)
                                                                 ---------     ---------
        Net Cash Flows Used For Financing Activities . . . . . .  (357,086)      (48,192)
                                                                 ---------     ---------

Net Increase (Decrease) in Cash and Cash Equivalents . . . . . .  (131,838)       11,996
Cash and Cash Equivalents at Beginning of Period . . . . . . . .   157,138        89,652
                                                                 ---------     ---------
Cash and Cash Equivalents at End of Period . . . . . . . . . . . $  25,300     $ 101,648
                                                                 =========     =========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $40,791,000  and
  $40,816,000  and for income taxes was  $64,597,000 and $24,645,000 in 2000 and
  1999, respectively.  Noncash acquisitions under capital leases were $8,422,000
  and $11,849,000 in 2000 and 1999, respectively.

See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>


                       OHIO POWER COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                  JUNE 30, 2000

                                   (UNAUDITED)

1.      GENERAL

               The accompanying  unaudited  consolidated  financial  state-ments
        should  be  read  in   conjunction   with  the  1999  Annual  Report  as
        incorporated  in and  filed  with the Form  10-K.  Certain  prior-period
        amounts   have  been   reclassified   to   conform   to   current-period
        presentation.  In the opinion of  management,  the financial  statements
        reflect all adjustments  (consisting of only normal recurring  accruals)
        which are necessary for a fair presentation of the results of operations
        for interim periods.

2.      FINANCING ACTIVITY

               In May 2000 the Company  issued $75  million of senior  unsecured
        notes with a floating  interest  rate due 2001.  The  Company has in the
        past,  and may in the future,  acquire  outstanding  debt and  preferred
        stock securities in open market transactions.
<PAGE>
3.      OHIO RESTRUCTURING LEGISLATION AND TRANSITION PLAN FILING

                   As discussed in Note 4 of the Notes to Consolidated Financial
        Statements in the 1999 Annual  Report,  the Ohio Electric  Restructuring
        Act of 1999 (the Act) provides for, among other things,  customer choice
        of  electricity  supplier,  a residential  rate  reduction of 5% for the
        generation portion of rates and a freezing of generation rates including
        fuel rates  beginning  on January 1, 2001.  The Act also  provides for a
        five-year  transition  period  to move from  cost-based  rates to market
        pricing for  generation  services.  It authorizes  the Public  Utilities
        Commission  of Ohio (PUCO) to address  certain major  transition  issues
        including  unbundling  of rates and the  recovery of  generation-related
        transition costs which include regulatory assets,  asset impairments and
        other stranded costs,  employee severance and retraining costs, consumer
        education  costs and other costs.  Stranded costs are  generation  costs
        that are not deemed to be recoverable in a competitive market.

     On March 28,  2000,  the PUCO  staff  issued  its  report on the  Company's
        transition plan filing. On May 8, 2000, a stipulation  agreement between
        the  Company,  the PUCO  staff,  the Ohio  Consumers'  Counsel and other
        concerned  parties  was  filed  with  the  PUCO  for  approval.  The key
        provisions of the stipulation agreement are:

         -        Recovery of  generation-related  regulatory  assets over seven
                  years will be through a frozen  transition  rate for the first
                  five years and a wires charge for the remaining years.

         - There will be no shopping incentive for the Company's customers.

         -        The  Company  is to absorb the first $20  million of  consumer
                  education,  implementation  and  transition  plan filing costs
                  with deferral of the remaining costs,  plus a carrying charge,
                  as a  regulatory  asset for  recovery  in future  distribution
                  rates.

         -        The  Company  and  its  affiliate,   Columbus  Southern  Power
                  Company,  will make  available  a fund of up to $10 million to
                  reimburse  customers  who choose to purchase  their power from
                  another  company for certain  transmission  charges imposed by
                  the   Pennsylvania  -  New  Jersey  -  Maryland   transmission
                  organization   (PJM)  and/or  a  midwest   independent  system
                  operator  (Midwest  ISO)  on  generation  originating  in  the
                  Midwest ISO or PJM areas.

         -        The  statutory 5% reduction in the  generation  component of
                  residential tariffs will remain in effect for the entire
                  transition period.
         -        The Company's  request for a $50 million gross  receipts tax
                  rider to recover  duplicate  gross  receipts tax will be
                  separately litigated.

                  Hearings on the  stipulation  and the gross receipts tax issue
         were held in June 2000.  Approval of the  stipulation  agreement by the
         PUCO and a decision on the gross receipts tax are pending.

                  Management  has  concluded  that  as  of  June  30,  2000  the
         requirements  to apply  Statement  of  Financial  Accounting  Standards
         (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation,"
         continue  to be met  since the  Company's  rates  for  generation  will
         continue to be cost-based  regulated until the PUCO takes action on the
         transition plan as required by the Act. The  establishment of rates and
         wires  charges under a PUCO  approved  transition  plan will enable the
         Company to determine its ability to recover  stranded  costs  including
         regulatory  assets,  and  other  transition  costs,  a  requirement  to
         discontinue application of SFAS 71.

                  When  the  transition   plan  and  transition   period  tariff
         schedules are approved, the application of SFAS 71 will be discontinued
         for the Ohio retail jurisdictional  portion of the generating business.
         Management expects this to occur when the PUCO approves the stipulation
         agreement for the Company's  transition  plan filing.  The Act requires
         that the PUCO issue its order to  approve  transition  plan  filings no
         later than October 31, 2000.


<PAGE>


                  Upon the  discontinuance  of SFAS 71 the Company  will have to
         write off its Ohio jurisdictional  generation-related regulatory assets
         to the extent that they cannot be recovered under the tariff  schedules
         in the  transition  plan  approved  by the PUCO and  record  any  asset
         accounting impairments in accordance with SFAS 121, "Accounting for the
         Impairment  of  Long-lived  Assets  and  for  Long-lived  Assets  to Be
         Disposed Of." An impairment loss would be recorded,  under SFAS 121, to
         the  extent  that the cost of  generating  assets  cannot be  recovered
         through   non-discounted   generation-related   revenues   during   the
         transition period and future market prices.

                  The amount of regulatory  assets recorded on the books at June
         30,  2000  applicable  to the  Ohio  retail  jurisdictional  generating
         business is $456 million before related tax effects. Due to the planned
         closing of the Company's  affiliated  mines,  including the Meigs mine,
         projected generation-related  regulatory assets as of December 31, 2000
         (the date that  recoverable  generation-related  regulatory  assets are
         measured under the Ohio law) allocable to the Ohio retail  jurisdiction
         are  estimated  to exceed  $520  million,  before  income tax  effects.
         Recovery of these  regulatory  assets is being  sought as a part of the
         Company's Ohio  transition plan filing.  Based on transition  rates and
         wires charges in the  stipulation  agreement and  management's  current
         projections  of future market  prices,  management  does not anticipate
         that the Company will  experience  material  tangible asset  accounting
         impairment  write-offs.  Whether the Company will  experience  material
         regulatory  asset  write-offs  will depend on whether the PUCO approves
         the Company's stipulation agreement which provides for their recovery.

                  A  determination  of whether the Company will  experience  any
         asset   impairment  loss  regarding  its  Ohio  retail   jurisdictional
         generating  assets  and any loss from a possible  inability  to recover
         Ohio  generation-related  regulatory  assets and other transition costs
         cannot be made until the PUCO takes action on the Company's stipulation
         agreement.  Should  the  PUCO  fail  to  fully  approve  the  Company's
         stipulation  agreement  and  its  transition  tariff  schedules,  which
         include recovery of the Company's generation-related regulatory assets,
         stranded costs and other transition costs including the duplicate gross
         receipts  tax,  it could have a material  adverse  effect on results of
         operations, cash flows and possibly financial condition.

4.       MONEY POOL

                  On June 15,  2000,  the Company  became a  participant  in the
        American  Electric Power (AEP) System Money Pool (Money Pool). The Money
        Pool is a mechanism  structured to meet the short-term cash requirements
        of the  participants  with  AEP  Company,  Inc.  acting  as the  primary
        borrower on behalf of the Money Pool. The Company's  affiliates that are
        U.S.  domestic  electric  utility  operating  companies  are the primary
        participants in the Money Pool.

                  The  operation  of the Money  Pool is  designed  to match on a
        daily  basis  the  available  cash  and  borrowing  requirements  of the
        participants. Participants with excess cash loan funds to the Money Pool
        reducing the amount of external funds AEP Company,  Inc. needs to borrow
        to meet the short-term  cash  requirements  of other  participants  with
        advances from the Money Pool. AEP Company, Inc. borrows the funds needed
        on a daily  basis to meet the net cash  requirements  of the Money  Pool
        participants. A weighted average daily interest rate which is calculated
        based on the outstanding short-term debt borrowings made by AEP Company,
        Inc.  is  applied to each Money  Pool  participant's  daily  outstanding
        investment  or debt  position to determine  interest  income or interest
        expense.  Interest  income  is  included  in  nonoperating  income,  and
        interest  expense  is  included  in  interest  charges.  As a result  of
        becoming a Money Pool  participant,  the Company  retired its short-term
        debt.  At June 30, 2000 the Company was a net investor in the Money Pool
        and reports its  investment  in the Money Pool as Advances to Affiliates
        on the Balance Sheets.

5.      FACTORING OF RECEIVABLES

               In  June  2000,  Ohio  Power  Company  entered  into a  factoring
        arrangement with an affiliate,  CSW Credit,  Inc. Under this arrangement
        the  Company  sells  without  recourse  its  retail  customer   accounts
        receivable  and accrued  utility  revenue  balances to CSW Credit and is
        charged  a fee  based on CSW  Credit's  financing  costs,  uncollectible
        accounts  experience for the Company's  receivables  and  administrative
        costs. The costs of factoring  customer accounts  receivable is reported
        as an  operating  expense.  At June 30,  2000  the  amount  of  factored
        accounts receivable and accrued utility revenues was $106.2 million.
<PAGE>
6.      RATE MATTERS

            As  discussed  in  Note 2 of the  Notes  to  Consolidated  Financial
      Statements of the 1999 Annual  Report,  the AEP System  companies  filed a
      settlement agreement with the Federal Energy Regulatory  Commission (FERC)
      for their approval to establish an open access  transmission  tariff.  The
      Company  made a  provision  in 1999 for a refund  including  interest  for
      amounts paid in excess of the agreed to rate.

            On March 16, 2000, the FERC approved the settlement  agreement filed
      in December 1999  resolving  the issues on rehearing  raised in a July 30,
      1999 order. Under terms of the settlement, AEP is required to make refunds
      retroactive to September 7, 1993 to certain customers affected by the July
      30, 1999 FERC order.  Pursuant to FERC orders the refunds were made in two
      payments,  the first  payment  was made in  February  2000 and the  second
      payment was made on August 1, 2000. In addition, a new lower rate of $1.55
      kw/month became effective on January 1, 2000, for all transmission service
      customers and a rate of $1.42 kw/month was  established and took effect on
      June 16, 2000 in connection  with the  consummation of the AEP and Central
      and South West Corporation merger.  Prior to January 1, 2000, the rate was
      $2.04  kw/month.  Unless the  Company  and the  market  grow the volume of
      physical  power  transactions  to  increase  the  utilization  of the  AEP
      System's  transmission  lines, the new open access  transmission rate will
      adversely impact future results of operations and cash flows.
<PAGE>

7.      CONTINGENCIES

        Litigation

                  As discussed in Note 5 of the Notes to Consolidated  Financial
         Statements  in the 1999 Annual  Report,  the  deductibility  of certain
         interest  deductions  related to AEP's  corporate  owned life insurance
         (COLI)  program for taxable  years 1991 through 1996 is under review by
         the Internal  Revenue Service (IRS).  Adjustments  have been or will be
         proposed  by  the  IRS   disallowing   COLI  interest   deductions.   A
         disallowance  of the COLI  interest  deductions  through  June 30, 2000
         would  reduce  earnings  by  approximately   $118  million   (including
         interest).

                  The Company made  payments of taxes and interest  attributable
         to COLI  interest  deductions  for taxable  years 1991  through 1998 to
         avoid  the  potential  assessment  by the IRS of any  additional  above
         market rate interest on the contested  amount.  The payments to the IRS
         are included on the  consolidated  balance sheet in other  property and
         investments  pending  the  resolution  of this  matter.  The Company is
         seeking refund through litigation of all amounts paid plus interest.

                  In order to resolve this issue, the Company filed suit against
         the United States in the U.S.  District Court for the Southern District
         of  Ohio in  1998.  In  1999 a U.S.  Tax  Court  judge  decided  in the
         Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI
         interest  deduction  should  be  disallowed.  Notwithstanding  the  Tax
         Court's  decision in  Winn-Dixie,  management has made no provision for
         any  possible  adverse  earnings  impact  from this  matter  because it
         believes,  and has  been  advised  by  outside  counsel,  that it has a
         meritorious  position and will  vigorously  pursue its lawsuit.  In the
         event the  resolution  of this  matter is  unfavorable,  it will have a
         material  adverse  impact on  results  of  operations,  cash  flows and
         possibly financial condition.

         Federal EPA Complaint and Notice of Violation

                  As discussed in Note 5 of the Notes to Consolidated  Financial
         Statements in the 1999 Annual Report,  the Company has been involved in
         litigation regarding  generating plant emissions.  Notices of Violation
         were  issued  and a  complaint  was  filed  by the  U.S.  Environmental
         Protection Agency (Federal EPA) in the U.S. District Court that alleges
         the Company,  certain affiliates and eleven unaffiliated utilities made
         modifications  to  generating  units at  certain  of  their  coal-fired
         generating plants over the course of the past 25 years that extend unit
         operating  lives  or  increase  unit  generating   capacity  without  a
         preconstruction permit in violation of the Clean Air Act. The complaint
         was amended in March 2000 to add  allegations  for  certain  generating
         units previously  named in the complaint and to include  additional AEP
         System  generating  units  previously  named  only  in the  Notices  of
         Violation  in the  complaint.  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.

                  A number of northeastern and eastern states were granted leave
         to intervene in the Federal EPA's action  against the Company under the
         Clean Air Act. A lawsuit  against  power  plants  owned by the  Company
         alleging  similar  violations to those in the Federal EPA complaint and
         Notices of Violation was filed by a number of special  interest  groups
         and has been consolidated with the Federal EPA action.

                  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). Civil penalties, if ultimately imposed by the court,
         and the cost of any required new pollution  control  equipment,  if the
         court accepts Federal EPA's contentions, could be substantial.

                  On May 10, 2000,  the Company  filed motions to dismiss all or
         portions of the complaints.  Briefing on these motions was completed on
         August  2,  2000.  Management  believes  its  maintenance,  repair  and
         replacement  activities  were in conformity  with the Clean Air Act and
         intends to vigorously pursue its defense of this matter.

                  In the event the  Company  does 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,  stranded
         cost wires charges and future market prices for energy.

         NOx Reductions

                  As discussed in Note 6 of the Notes to Consolidated  Financial
         Statements  in the 1999 Annual  Report,  Federal EPA had issued a final
         rule (the NOx rule) that  requires  substantial  reductions in nitrogen
         oxide (NOx) emissions in 22 eastern states, including certain states in
         which the AEP  System's  generating  plants  are  located.  A number of
         utilities,  including certain AEP System companies, had filed petitions
         seeking a review of the final rule in the U.S. Court of Appeals for the
         District of Columbia Circuit (Appeals Court).  In May 1999, the Appeals
         Court  indefinitely  stayed the requirement that states develop revised
         air quality programs to impose the NOx reductions but did not, however,
         stay the  final  compliance  date of May 1,  2003.  In  March  2000 the
         Appeals  Court issued a decision  generally  upholding the NOx rule. On
         April 20,  2000,  certain AEP System  companies  and other  petitioners
         filed for  rehearing  of this  decision  including a  rehearing  by the
         entire  Appeals  Court.  On June 22, 2000, the Appeals Court denied the
         petition  for  rehearing  and  lifted the stay  related to the  states'
         development  of  revised  air  quality   programs  to  impose  the  NOx
         reductions.  The  petition  for a rehearing  before the entire  Appeals
         Court was also denied. The AEP System companies subject to the NOx rule
         plan to appeal to the U.S. Supreme Court.

                  In June 2000 the  Company  announced  that it was  beginning a
         $175  million  installation  of  selective  catalytic  reduction  (SCR)
         technology to reduce NOx emissions on its two-unit 2,600 megawatt Gavin
         Plant.  The Company  intends to have the SCR equipment  operational  in
         2001.

                  Preliminary  estimates  indicate that  compliance with the NOx
         rule upheld by the  Appeals  Court  could  result in  required  capital
         expenditures  of  approximately  $624  million for the  Company.  Since
         compliance costs cannot be estimated with certainty, the actual cost to
         comply could be significantly  different than the Company's preliminary
         estimate depending upon the compliance alternatives selected to achieve
         reductions  in NOx  emissions.  Unless  such costs are  recovered  from
         customers  through  regulated  rates and/or  future  market  prices for
         electricity,  they will have an  adverse  effect on future  results  of
         operations, cash flows and possibly financial condition.

         Other

                  The Company  continues to be involved in certain other matters
discussed in the 1999 Annual Report.


<PAGE>


                       OHIO POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                             AND FINANCIAL CONDITION

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
                     ---------------------------------------

RESULTS OF OPERATIONS

         Net  income  increased  $6  million  or 12% for the  quarter  due to an
increase in wholesale sales. For the year-to-date  period increases in operating
expenses  more than  offset  the  effects of the  increase  in  wholesale  sales
resulting in a decline in net income of $8 million or 7%.

         Income statement line items which changed significantly were:

                                     Increase (Decrease)

                             Second Quarter       Year-to-Date

                            (in millions)  %   (in millions)   %

Operating Revenues . . . .       $42       8         $69       7
Fuel Expense . . . . . . .         8       5          34      10
Purchased Power Expense. .        11      32          25      45
Maintenance Expense. . . .         5      18           8      14
Federal Income Tax . . . .         6      22              4       6

         The increase in operating revenues resulted from increased sales to the
American  Electric Power System Pool (AEP Power Pool) and the Company's share of
increased transactions to neighboring utility systems and power marketers by the
AEP Power  Pool.  The  Company as a member of the AEP Power  Pool  shares in the
revenues and cost of the AEP Power Pool's  wholesale sales and forward trades to
neighboring  utility systems and power  marketers.  The Company's share of these
AEP Power Pool  transactions  within the AEP System  traditional  marketing area
(within  two  transmission  systems of AEP System)  are  recorded  as  operating
revenues and  purchases  accounting  for the increases in revenues and purchased
power expense.  Forward  trading sales and purchases are recorded on a net basis
in  operating  revenues.   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.  As a result of the  Company's  major
industrial  customer's  decision not to continue its purchase  power  agreement,
additional  power was  delivered  to AEP Power Pool  accounting  for part of the
increase in revenues.

         Fuel expense  increased  due to an increase in the average cost of fuel
consumed  reflecting  shutdown costs included in the cost of coal delivered from
affiliated mining operations.

         Additional  boiler  repairs  accounted for the increase in  maintenance
expense.

         The increase in operating  federal income tax expense was primarily due
to an increase in pre-tax operating book income.

FINANCIAL CONDITION
         Total plant and property  additions  including  capital  leases for the
         year-to-date  period were $100 million.  During the first six months of
         2000 the Company's  subsidiaries issued $75 million principal amount of
         long-term obligations

at variable interest rates and retired $12 million principal amount of long-term
debt with interest  rates  ranging from 7.10% to 7.30% and decreased  short-term
debt by $195 million from year-end  balances.  The Company has in the past,  and
may in the future,  acquire  outstanding  debt and preferred stock securities in
open market transactions.

         During the second  quarter the AEP System  established  a Money Pool to
coordinate short-term borrowings for certain of its subsidiaries,  primarily the
U.S. domestic electric utility operating  companies,  including the Company. The
operation of the Money Pool is designed to match on a daily basis the  available
cash and borrowing requirements of the participants, thereby minimizing the need
for  borrowings  from  external  sources.   The  daily  cash  positions  of  the
participants  are netted and if there is a  deficiency  in cash,  the Money Pool
raises  funds  through  external  borrowing.  If there is a net  excess in cash,
existing  external  borrowings  are paid  down,  or,  if there  are no  external
borrowings maturing, the excess funds are invested.

        CSW  Credit,  Inc.,  a  subsidiary  of AEP,  factors  electric  customer
accounts   receivable  for  affiliated   operating  companies  and  unaffiliated
companies.  In June 2000 the  factoring  of  customer  accounts  receivable  for
affiliated  companies  was  expanded  as a result of the merger to  include  the
Company. At June 30, 2000 the amount factored was $106 million.

OTHER MATTERS

Ohio Restructuring Legislation and Transition Plan Filing

    As discussed in Note 4 of the Notes to Consolidated  Financial Statements in
the 1999 Annual Report,  the Ohio Electric  Restructuring  Act of 1999 (the Act)
provides for, among other things,  customer  choice of electricity  supplier,  a
residential  rate  reduction  of 5% for the  generation  portion  of rates and a
freezing of generation  rates including fuel rates beginning on January 1, 2001.
The Act also provides for a five-year  transition period to move from cost-based
rates to market  pricing  for  generation  services.  It  authorizes  the Public
Utilities  Commission of Ohio (PUCO) to address certain major transition  issues
including unbundling of rates and the recovery of generation-related  transition
costs which include  regulatory  assets,  asset  impairments  and other stranded
costs,  employee  severance and retraining costs,  consumer  education costs and
other  costs.  Stranded  costs are  generation  costs  that are not deemed to be
recoverable in a competitive market.

     On March 28,  2000,  the PUCO  staff  issued  its  report on the  Company's
transition  plan filing.  On May 8, 2000, a  stipulation  agreement  between the
Company, the PUCO staff, the Ohio Consumers' Counsel and other concerned parties
was filed with the PUCO for  approval.  The key  provisions  of the  stipulation
agreement are:

o Recovery  of  generation-related  regulatory  assets  over seven years will be
through a frozen transition rate for the first five years and a wires charge for
the  remaining  years.  o There will be no shopping  incentive for the Company's
customers.

o The  Company  is to absorb  the  first  $20  million  of  consumer  education,
implementation  and transition  plan filing costs with deferral of the remaining
costs,  plus a carrying  charge,  as a  regulatory  asset for recovery in future
distribution  rates.  o The Company and its affiliate,  Columbus  Southern Power
Company,  will make available a fund of up to $10 million to reimburse customers
who choose to purchase their power from another company for certain transmission
charges  imposed  by the  Pennsylvania  - New  Jersey  -  Maryland  transmission
organization (PJM) and/or a midwest independent system operator (Midwest ISO) on
generation originating in the Midwest ISO or PJM areas.

o The statutory 5% reduction in the generation  component of residential tariffs
will remain in effect for the entire transition  period. o The Company's request
for a $50 million gross receipts tax rider to recover  duplicate  gross receipts
tax will be separately litigated.

         Hearings on the  stipulation and the gross receipts tax issue were held
in June 2000.  Approval of the stipulation  agreement by the PUCO and a decision
on the gross receipts tax are pending.

         Management has concluded that as of June 30, 2000 the  requirements  to
apply Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the
Effects of Certain Types of Regulation,"  continue to be met since the Company's
rates for  generation  will continue to be cost-based  regulated  until the PUCO
takes action on the transition plan as required by the Act. The establishment of
rates and wires charges under a PUCO  approved  transition  plan will enable the
Company to determine its ability to recover stranded costs including  regulatory
assets, and other transition costs, a requirement to discontinue  application of
SFAS 71.

         When the  transition  plan and transition  period tariff  schedules are
approved,  the application of SFAS 71 will be  discontinued  for the Ohio retail
jurisdictional  portion of the generating  business.  Management expects this to
occur  when  the PUCO  approves  the  stipulation  agreement  for the  Company's
transition  plan  filing.  The Act  requires  that the PUCO  issue  its order to
approve transition plan filings no later than October 31, 2000.

         Upon the  discontinuance  of SFAS 71 the Company will have to write off
its Ohio jurisdictional  generation-related regulatory assets to the extent that
they cannot be  recovered  under the tariff  schedules  in the  transition  plan
approved by the PUCO and record any asset  accounting  impairments in accordance
with SFAS 121,  "Accounting  for the  Impairment  of  Long-lived  Assets and for
Long-lived  Assets to Be Disposed  Of." An  impairment  loss would be  recorded,
under  SFAS 121,  to the extent  that the cost of  generating  assets  cannot be
recovered  through   non-discounted   generation-related   revenues  during  the
transition period and future market prices.

         The amount of regulatory  assets recorded on the books at June 30, 2000
applicable to the Ohio retail jurisdictional generating business is $456 million
before  related  tax  effects.  Due  to the  planned  closing  of the  Company's
affiliated  mines,  including  the  Meigs  mine,  projected   generation-related
regulatory   assets  as  of  December  31,  2000  (the  date  that   recoverable
generation-related  regulatory assets are measured under the Ohio law) allocable
to the Ohio retail  jurisdiction  are estimated to exceed $520  million,  before
income tax  effects.  Recovery of these  regulatory  assets is being sought as a
part of the Company's Ohio transition plan filing. Based on transition rates and
wires charges in the stipulation  agreement and management's current projections
of future market prices,  management  does not anticipate  that the Company will
experience material tangible asset accounting impairment write-offs. Whether the
Company will  experience  material  regulatory  asset  write-offs will depend on
whether the PUCO approves the Company's stipulation agreement which provides for
their recovery.

         A  determination  of whether  the  Company  will  experience  any asset
impairment loss regarding its Ohio retail  jurisdictional  generating assets and
any loss from a possible inability to recover Ohio generation-related regulatory
assets and other  transition costs cannot be made until the PUCO takes action on
the Company's stipulation  agreement.  Should the PUCO fail to fully approve the
Company's  stipulation  agreement and its  transition  tariff  schedules,  which
include recovery of the Company's generation-related regulatory assets, stranded
costs and other  transition costs including the duplicate gross receipts tax, it
could have a material  adverse effect on results of  operations,  cash flows and
possibly financial condition.

COLI Litigation

         As  discussed  in  Note  5  of  the  Notes  to  Consolidated  Financial
Statements in the 1999 Annual  Report,  the  deductibility  of certain  interest
deductions  related to AEP's corporate  owned life insurance  (COLI) program for
taxable years 1991 through 1996 is under review by the Internal  Revenue Service
(IRS).  Adjustments  have been or will be proposed by the IRS  disallowing  COLI
interest deductions. A disallowance of the COLI interest deductions through June
30,  2000  would  reduce  earnings  by  approximately  $118  million  (including
interest).

         The Company made  payments of taxes and interest  attributable  to COLI
interest  deductions  for taxable years 1991 through 1998 to avoid the potential
assessment  by the IRS of any  additional  above  market  rate  interest  on the
contested  amount.  The  payments to the IRS are  included  on the  consolidated
balance sheet in other property and  investments  pending the resolution of this
matter.  The Company is seeking  refund  through  litigation of all amounts paid
plus interest.

         In order to resolve  this  issue,  the Company  filed suit  against the
United States in the U.S.  District  Court for the Southern  District of Ohio in
1998.  In 1999 a U.S.  Tax  Court  judge  decided  in the  Winn-Dixie  Stores v.
Commissioner case that a corporate  taxpayer's COLI interest deduction should be
disallowed.  Notwithstanding the Tax Court's decision in Winn-Dixie,  management
has made no provision for any possible  adverse earnings impact from this matter
because it  believes,  and has been  advised by outside  counsel,  that it has a
meritorious  position and will vigorously  pursue its lawsuit.  In the event the
resolution of this matter is unfavorable, it will have a material adverse impact
on results of operations,  cash flows and possibly financial condition.  Federal
EPA Complaint and Notice of Violation

         As  discussed  in  Note  5  of  the  Notes  to  Consolidated  Financial
Statements  in the  1999  Annual  Report,  the  Company  has  been  involved  in
litigation  regarding  generating  plant  emissions.  Notices of Violation  were
issued and a complaint  was filed by the U.S.  Environmental  Protection  Agency
(Federal  EPA) in the U.S.  District  Court that  alleges the  Company,  certain
affiliates and eleven  unaffiliated  utilities made  modifications to generating
units at certain of their  coal-fired  generating  plants over the course of the
past 25 years that  extend unit  operating  lives or  increase  unit  generating
capacity without a preconstruction permit in violation of the Clean Air Act. The
complaint was amended in March 2000 to add  allegations  for certain  generating
units  previously  named in the complaint and to include  additional  AEP System
generating  units  previously  named  only in the  Notices of  Violation  in the
complaint.  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.

         A number of  northeastern  and  eastern  states were  granted  leave to
intervene in the Federal  EPA's action  against the Company  under the Clean Air
Act. A lawsuit  against  power  plants  owned by the  Company  alleging  similar
violations  to those in the Federal EPA  complaint  and Notices of Violation was
filed by a number of special interest groups and has been  consolidated with the
Federal EPA action.

         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). Civil penalties,  if ultimately imposed by the court, and the cost of any
required new pollution  control  equipment,  if the court accepts  Federal EPA's
contentions, could be substantial.

         On May 10, 2000,  the Company  filed motions to dismiss all or portions
of the  complaints.  Briefing on these  motions was completed on August 2, 2000.
Management believes its maintenance,  repair and replacement  activities were in
conformity  with the Clean Air Act and intends to vigorously  pursue its defense
of this matter.

         In the event the Company  does 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,  stranded cost wires charges and future market prices
for energy.

NOx Reductions

         As  discussed  in  Note  6  of  the  Notes  to  Consolidated  Financial
Statements in the 1999 Annual  Report,  Federal EPA had issued a final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide (NOx) emissions
in 22  eastern  states,  including  certain  states  in which  the AEP  System's
generating  plants are located.  A number of  utilities,  including  certain AEP
System companies,  had filed petitions seeking a review of the final rule in the
U.S. Court of Appeals for the District of Columbia Circuit  (Appeals Court).  In
May 1999,  the Appeals Court  indefinitely  stayed the  requirement  that states
develop  revised air quality  programs to impose the NOx reductions but did not,
however,  stay the  final  compliance  date of May 1,  2003.  In March  2000 the
Appeals Court issued a decision  generally  upholding the NOx rule. On April 20,
2000,  certain AEP System companies and other petitioners filed for rehearing of
this decision  including a rehearing by the entire  Appeals  Court.  On June 22,
2000,  the Appeals  Court denied the petition for  rehearing and lifted the stay
related to the states' development of revised air quality programs to impose the
NOx reductions. The petition for a rehearing before the entire Appeals Court was
also denied.  The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.

         In June 2000 the Company announced that it was beginning a $175 million
installation of selective  catalytic  reduction  (SCR)  technology to reduce NOx
emissions on its two-unit  2,600 megawatt  Gavin Plant.  The Company  intends to
have the SCR equipment operational in 2001.

         Preliminary estimates indicate that compliance with the NOx rule upheld
by  the  Appeals  Court  could  result  in  required  capital   expenditures  of
approximately  $624 million for the Company.  Since  compliance  costs cannot be
estimated  with  certainty,  the actual  cost to comply  could be  significantly
different than the Company's  preliminary estimate depending upon the compliance
alternatives selected to achieve reductions in NOx emissions.  Unless such costs
are recovered from customers through regulated rates and/or future market prices
for  electricity,  they  will  have an  adverse  effect  on  future  results  of
operations, cash flows and possibly financial condition.

Market Risks

        The Company has certain market risks inherent in its business activities
from changes in electricity  commodity  prices and interest  rates.  Market risk
represents  the risk of loss that may impact the Company due to adverse  changes
in commodity market prices and interest rates. The Company's  exposure to market
risk  from  the  trading  of  electricity  and  related   financial   derivative
instruments,  which are allocated to the Company  through the American  Electric
Power  System  Power  Pool,  were less than $7 million  at June 30,  2000 and $4
million at December 31, 1999 based on the use of a risk measurement  model which
calculates  Value at Risk (VaR).  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 three-day holding period.

        The exposure to changes in interest rates from the Company's  short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.


<PAGE>
<TABLE>
<CAPTION>


               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           -------------------    --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)

<S>                                        <C>        <C>          <C>        <C>
OPERATING REVENUES . . . . . . . . . . .   $209,172   $178,699     $370,501   $329,729
                                           --------   --------     --------   --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .     75,808     64,916      147,394    126,797
  Purchased Power. . . . . . . . . . . .     31,541     16,128       52,207     30,172
  Other Operation. . . . . . . . . . . .     28,476     27,140       52,232     53,658
  Maintenance. . . . . . . . . . . . . .     13,408     12,720       21,995     21,927
  Depreciation and Amortization. . . . .     18,926     18,544       37,838     36,999
  Taxes Other Than Federal Income Taxes.      8,819      9,217       16,058     19,238
  Federal Income Taxes . . . . . . . . .      7,692      6,862        7,415      5,735
                                           --------   --------    ---------   --------

          TOTAL OPERATING EXPENSES . . .    184,670    155,527      335,139    294,526
                                           --------   --------    ---------   --------

OPERATING INCOME . . . . . . . . . . . .     24,502     23,172       35,362     35,203

NONOPERATING INCOME (LOSS) . . . . . . .        494         11          716       (510)
                                           --------   --------    ---------   --------

INCOME BEFORE INTEREST CHARGES . . . . .     24,996     23,183       36,078     34,693

INTEREST CHARGES . . . . . . . . . . . .     10,296      9,228       20,213     18,315
                                           --------   --------     --------   --------

NET INCOME . . . . . . . . . . . . . . .     14,700     13,955       15,865     16,378

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

EARNINGS APPLICABLE TO COMMON STOCK. . .   $ 14,647   $ 13,902     $ 15,759   $ 16,272
                                           ========   ========     ========   ========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           ------------------     --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD
  AS PREVIOUSLY REPORTED . . . . . . . .   $126,642  $132,493     $142,018    $144,626
CONFORMING CHANGE IN ACCOUNTING POLICY .     (3,294)   (2,183)      (2,782)     (1,686)
                                           --------  --------     --------    --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD.    123,348   130,310      139,236     142,940
NET INCOME . . . . . . . . . . . . . . .     14,700    13,955       15,865      16,378

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .     17,000    15,000       34,000      30,000
    Preferred Stock. . . . . . . . . . .         53        53          106         106
                                           --------  --------     --------    --------

BALANCE AT END OF PERIOD . . . . . . . .   $120,995  $129,212     $120,995    $129,212
                                           ========  ========     ========    ========

The common  stock of the  Company is wholly  owned by  American  Electric  Power
Company, Inc.

See Notes to Consolidated Financial Statements.

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


               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                          <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .  $  914,172     $  916,889
  Transmission. . . . . . . . . . . . . . . . . . . . . . .     393,352        392,029
  Distribution. . . . . . . . . . . . . . . . . . . . . . .     917,585        897,516
  General . . . . . . . . . . . . . . . . . . . . . . . . .     208,235        217,368
  Construction Work in Progress . . . . . . . . . . . . . .      84,471         35,903
                                                             ----------     ----------
          Total Electric Utility Plant. . . . . . . . . . .   2,517,815      2,459,705
  Accumulated Depreciation and Amortization . . . . . . . .   1,125,365      1,114,255
                                                             ----------     ----------

          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .   1,392,450      1,345,450
                                                             ----------     ----------

OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . .      43,814         46,205
                                                             ----------     ----------

CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .       1,976          3,077
  Accounts Receivable:
    Customers . . . . . . . . . . . . . . . . . . . . . . .      33,159         32,301
    Affiliated Companies. . . . . . . . . . . . . . . . . .       4,033          2,283
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .      23,254         24,143
  Materials and Supplies. . . . . . . . . . . . . . . . . .      33,246         34,289
  Under-recovered Fuel Costs. . . . . . . . . . . . . . . .      32,040          6,469
  Tax Benefits Receivable . . . . . . . . . . . . . . . . .       3,933           -
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .       2,099          1,668
                                                             ----------     ----------

          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     133,740        104,230
                                                             ----------     ----------

DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      10,494         12,124
                                                             ----------     ----------

TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . .  $1,580,498     $1,508,009
                                                             ==========     ==========

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


               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $15 Par Value:
    Authorized Shares: 11,000,000
    Issued 10,482,000 shares and
<S>                                                          <C>            <C>
    Outstanding Shares: 9,013,000 . . . . . . . . . . . . .  $  157,230     $  157,230
  Paid-in Capital . . . . . . . . . . . . . . . . . . . . .     180,000        180,000
  Retained Earnings . . . . . . . . . . . . . . . . . . . .     120,995        139,236
                                                             ----------     ----------
          Total Common Shareholder's Equity . . . . . . . .     458,225        476,466
                                                             ----------     ----------

Cumulative Preferred Stock Not Subject

    To Mandatory Redemption . . . . . . . . . . . . . . . .       5,283          5,286
  PSO-Obligated, Mandatorily Redeemable Preferred
    Securities of Subsidiary Trust Holding Solely Junior

    Subordinated Debentures of PSO. . . . . . . . . . . . .      75,000         75,000
  Long-term Debt. . . . . . . . . . . . . . . . . . . . . .     344,669        364,516
                                                             ----------     ----------

          TOTAL CAPITALIZATION. . . . . . . . . . . . . . .     883,177        921,268
                                                             ----------     ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .      30,000         20,000
  Advances from Affiliates. . . . . . . . . . . . . . . . .     148,859         79,169
  Accounts Payable - General. . . . . . . . . . . . . . . .      85,019         44,088
  Accounts Payable - Affiliated Companies . . . . . . . . .      43,374         35,195
  Customer Deposits . . . . . . . . . . . . . . . . . . . .      18,149         17,752
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .        -            18,480
  Interest Accrued. . . . . . . . . . . . . . . . . . . . .       7,716          5,420
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      11,711          8,381
                                                             ----------     ----------

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     344,828        228,485
                                                             ----------     ----------

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     302,213        281,916
                                                             ----------     ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . .       36,678         37,574
                                                             ----------     ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS . . . . . . . .      13,602         38,766
                                                             ----------     ----------

CONTINGENCIES (Note 4)

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $1,580,498     $1,508,009
                                                             ==========     ==========

See Notes to Consolidated Financial Statements.

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



               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                  Six Months Ended

                                    June 30,

                                                                2000           1999
                                                                ----           ----
                                                                   (in thousands)
OPERATING ACTIVITIES:
<S>                                                           <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 15,865       $ 16,378
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    39,039         37,488
    Deferred Income Taxes. . . . . . . . . . . . . . . . . .    17,079          3,156
    Deferred Investment Tax Credits. . . . . . . . . . . . .      (896)          (896)
  Changes in Certain Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (2,608)         2,983
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     1,932         (2,286)
    Equity and Other Investments . . . . . . . . . . . . . .     3,504         (4,831)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    49,110         (7,499)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .   (22,413)        (7,474)
    Other Deferred Credits . . . . . . . . . . . . . . . . .   (18,599)         4,791
    Fuel Recovery. . . . . . . . . . . . . . . . . . . . . .   (25,571)          (252)
    Other. . . . . . . . . . . . . . . . . . . . . . . . . .     2,567         (1,595)
                                                              --------       --------
        Net Cash Flows From Operating Activities . . . . . .    59,009         39,963
                                                              --------       --------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (80,997)       (48,495)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .    (4,694)          (184)
                                                              --------       --------
        Net Cash Flows Used For Investing Activities . . . .   (85,691)       (48,679)
                                                              --------       --------

FINANCING ACTIVITIES:
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (10,000)          -
  Retirement of Cumulative Preferred Stock . . . . . . . . .        (1)          -
  Advances from Affiliates . . . . . . . . . . . . . . . . .    69,690         37,381
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (34,000)       (30,000)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .      (108)          (106)
                                                              --------       --------
        Net Cash Flows From Financing Activities . . . . . .    25,581          7,275
                                                              --------       --------

Net Decrease in Cash and Cash Equivalents. . . . . . . . . .    (1,101)        (1,441)
Cash and Cash Equivalents at Beginning of Period . . . . . .     3,077          4,670
                                                              --------       --------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  1,976       $  3,229
                                                              ========       ========



Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $16,754,000  and
  $17,649,000  and for income taxes was  $11,725,000 and $13,603,000 in 2000 and
  1999, respectively.

See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>




               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                  JUNE 30, 2000

                                   (UNAUDITED)

1.      GENERAL

        The accompanying  unaudited  consolidated financial statements should be
read in  conjunction  with the Company's  1999 Form 10-K.  Certain  prior-period
amounts have been reclassified to conform to current-period presentation. In the
opinion  of  management,   the  financial  statements  reflect  all  adjustments
(consisting of only normal  recurring  accruals)  which are necessary for a fair
presentation of the results of operations for interim periods.

6.       MERGER

        In June 2000 the merger of American Electric Power Company,
Inc.  and  Central  and South West  Corporation,  the  parent  company of Public
Service Company of Oklahoma, was completed. As part of the change in control, an
adjustment  to conform the Company's  accounting  for vacation pay accruals with
American Electric Power's accounting policy was necessary.

        The  effect of the  conforming  entry was to reduce  net  assets by $2.8
million at December 31, 1999 and reduce net income by $0.5 million for the three
months  ended March 31, 2000 and by $0.2  million and $0.7 million for the three
months and six months ended June 30, 1999, respectively.

        In connection  with the merger,  a settlement  agreement was approved by
the Oklahoma  Corporation  Commission  that,  among other  things,  provides for
sharing  $50.2 million in guaranteed  net merger  savings over five years,  with
Oklahoma customers receiving approximately 55% of the savings. In the event that
actual net  merger  savings  are less than the  guaranteed  net merger  savings,
results of operations and cash flows will be adversely affected.

7.       FINANCING ACTIVITIES

        In March 2000 the  Company  redeemed  $10  million of 6.43%  medium-term
notes at maturity.

        The Company has in the past, and may in the future,  acquire outstanding
debt and preferred stock securities in open market transactions.

4.      CONTINGENCIES

        The Company continues to be involved in certain matters discussed in its
Form 10-K.


<PAGE>



                       PUBLIC SERVICE COMPANY OF OKLAHOMA

          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                            AND FINANCIAL CONDITION
 -------------------------------------------------------------------------------

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND

                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

         Net income for the second  quarter of 2000 rose $0.7 million or 5% as a
result of increased service revenues and nonoperating service income. Net income
for the first half of 2000  declined $0.5 million or 3% primarily as a result of
increased interest on short-term debt.

        Income statement line items which changed significantly were:

                                    Increase (Decrease)

                           Second Quarter     Year-to-Date

                           (in millions)   %  (in millions)   %

Operating Revenues . . . .      $30       17       $41       12
Fuel Expense . . . . . . .       11       17        21       16
Purchased Power Expense. .       15       96        22       73
Other Operation Expense. .        1        5        (1)      (3)
Taxes Other Than Federal
  Income Taxes . . . . . .       -       N.M.       (3)     (17)
Federal Income Taxes . . .        1       12         2       29
Nonoperating Income (Loss)       -       N.M.        1      N.M.
Interest Charges . . . . .        1       12         2       10

N.M. = Not Meaningful

         Operating  revenues  were  higher  due  primarily  to  an  increase  in
fuel-related  revenues  resulting from increased fuel expenses  explained below.
Fuel revenue  changes are  generally  offset by increases in fuel and  purchased
power  expenses  due to the  operation  of a fuel clause  mechanism in Oklahoma.
Also,  contributing  to the  increase in  revenues  in the  quarter  were higher
non-kwh related service revenues.

         The  increase in fuel was due  primarily  to a rise in the average unit
fuel cost due primarily to an increase in spot market natural gas prices.

         Purchased  power  expenses  increased due  primarily to higher  economy
energy purchases.

         Other  operation  expenses  were  higher  in  the  second  quarter  due
primarily to higher employee and customer  related expenses as well as increased
transmission and overhead distribution expenses.


<PAGE>


         Taxes other than federal  income taxes  decreased for the year- to-date
period due primarily to a favorable accrual adjustment to ad valorem tax expense
in 2000.

         Income tax expense  associated with utility  operations  increased as a
         result  of  an  increase  in  pre-tax  book  income.  The  increase  in
         nonoperating income for the first six months of 2000 primarily resulted
         from non-utility services to improve

energy efficiency.
        Interest charges increased reflecting additional short-term borrowings.

FINANCIAL CONDITION
        Total plant and property  additions for the year to date period were $81
        million.  In March  2000  the  Company  redeemed  $10  million  of 6.43%
        medium-term notes at maturity.

         The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.

MARKET RISKS

         The  Company  has  certain   market  risks  inherent  in  its  business
activities  from changes in interest  rates.  Market risk represents the risk of
loss that may impact the Company due to adverse changes in interest rates.

         The exposure to changes in interest rates from the Company's short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.


<PAGE>
<TABLE>
<CAPTION>


              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           -------------------    --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)
<S>                                        <C>        <C>          <C>        <C>
OPERATING REVENUES . . . . . . . . . . .   $272,409   $242,888     $484,565   $439,952
                                           --------   --------     --------   --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    113,773     91,690      203,125    167,961
  Purchased Power. . . . . . . . . . . .     19,252     10,573       30,950     16,766
  Other Operation. . . . . . . . . . . .     37,362     33,225       72,060     64,266
  Maintenance. . . . . . . . . . . . . .     20,906     22,018       35,212     34,262
  Depreciation and Amortization. . . . .     27,525     25,319       54,882     51,524
  Taxes Other Than Federal Income Taxes.     13,455     16,876       24,116     33,334
  Federal Income Taxes . . . . . . . . .      6,840      7,918        8,193     10,760
                                           --------   --------    ---------   --------

          TOTAL OPERATING EXPENSES . . .    239,113    207,619      428,538    378,873
                                           --------   --------    ---------   --------

OPERATING INCOME . . . . . . . . . . . .     33,296     35,269       56,027     61,079

NONOPERATING INCOME. . . . . . . . . . .        678        509          445        785
                                           --------   --------    ---------   --------

INCOME BEFORE INTEREST CHARGES . . . . .     33,974     35,778       56,472     61,864

INTEREST CHARGES . . . . . . . . . . . .     15,188     14,367       30,023     28,358
                                           --------   --------     --------   --------

NET INCOME . . . . . . . . . . . . . . .     18,786     21,411       26,449     33,506

PREFERRED STOCK DIVIDEND REQUIREMENTS. .         57         57          114        115
                                           --------   --------     --------   --------

EARNINGS APPLICABLE TO COMMON STOCK  . .   $ 18,729   $ 21,354     $ 26,335   $ 33,391
                                           ========   ========     ========   ========

                         STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           -------------------    --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD AS
  PREVIOUSLY REPORTED. . . . . . . . . .   $280,751   $286,188     $288,018    $300,592
   Conforming Change in Accounting . . .
     Policy. . . . . . . . . . . . . . .     (5,099)    (4,569)      (4,472)     (4,010)
                                           --------   --------     --------    --------

ADJUSTED BALANCE AT BEGINNING OF PERIOD.    275,652    281,619      283,546     296,582
 NET INCOME . . . . . . . . . . . . . . .    18,786     21,411       26,449      33,506

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock. . . . . . . . . . . . .    15,000     27,000       31,000      54,000
    Preferred Stock . . . . . . . . . . .        57         57          114         115
                                           --------   --------     --------    --------

BALANCE AT END OF PERIOD . . . . . . . .   $278,881   $275,973     $278,881    $275,973
                                           ========   ========     ========    ========

The Company is a wholly owned subsidiary of American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                          <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .  $1,406,484     $1,402,062
  Transmission. . . . . . . . . . . . . . . . . . . . . . .     512,270        484,327
  Distribution. . . . . . . . . . . . . . . . . . . . . . .     976,612        958,318
  General . . . . . . . . . . . . . . . . . . . . . . . . .     334,538        333,949
  Construction Work in Progress . . . . . . . . . . . . . .      53,672         52,775
                                                             ----------     ----------

          Total Electric Utility Plant. . . . . . . . . . .   3,283,576      3,231,431

  Accumulated Depreciation. . . . . . . . . . . . . . . . .   1,425,987      1,384,242
                                                             ----------     ----------

          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .   1,857,589      1,847,189
                                                             ----------     ----------

OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . .      38,436         37,080
                                                             ----------     ----------

CURRENT ASSETS:
  Cash. . . . . . . . . . . . . . . . . . . . . . . . . . .       2,014          2,018
  Accounts Receivable . . . . . . . . . . . . . . . . . . .      39,291         45,511
  Accounts Receivable - Affiliated Companies. . . . . . . .       3,898          6,053
  Materials and Supplies. . . . . . . . . . . . . . . . . .      25,968         26,420
  Fuel Inventory. . . . . . . . . . . . . . . . . . . . . .      67,186         60,844
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .      18,825         16,978
                                                             ----------     ----------

          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     157,182        157,824
                                                             ----------     ----------

REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      52,450         47,180
                                                             ----------     ----------

DEFERRED CHARGES  . . . . . . . . . . . . . . . . . . . . .      35,103         16,942
                                                             ----------     ----------

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $2,140,760     $2,106,215
                                                             ==========     ==========

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


              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $18 Par Value:
    Authorized - 7,600,000 Shares

<S>                                                         <C>            <C>
    Outstanding - 7,536,640 Shares. . . . . . . . . . . . .  $  135,660     $  135,660
  Paid-in Capital . . . . . . . . . . . . . . . . . . . . .     245,000        245,000
  Retained Earnings . . . . . . . . . . . . . . . . . . . .     278,881        283,546
                                                             ----------     ----------
          TOTAL COMMON SHAREHOLDER'S EQUITY . . . . . . . .     659,541        664,206

PREFERRED STOCK . . . . . . . . . . . . . . . . . . . . . .       4,704          4,706
SWEPCO-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED
 SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR
 SUBORDINATED DEBENTURES OF SWEPCO. . . . . . . . . . . . .     110,000        110,000
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . .     645,527        495,973
                                                             ----------     ----------

TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . .   1,419,772      1,274,885
                                                             ----------     ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .         595         45,595
  Advances from Affiliates. . . . . . . . . . . . . . . . .      63,242        140,897
  Accounts Payable - General. . . . . . . . . . . . . . . .      78,896         60,689
  Accounts Payable - Affiliated Companies . . . . . . . . .      50,899         39,117
  Customer Deposits . . . . . . . . . . . . . . . . . . . .      15,037         14,236
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      15,900         24,374
  Interest Accrued. . . . . . . . . . . . . . . . . . . . .      13,232          9,792
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      22,883         18,990
                                                             ----------     ----------

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     260,684        353,690
                                                             ----------     ----------

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     390,645        376,504

DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . .      55,408         57,649

DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . .      14,251         43,487
                                                             ----------     ----------

          TOTAL DEFERRED CREDITS. . . . . . . . . . . . . .     460,304        477,640
                                                             ----------     ----------

CONTINGENCIES (Note 5)

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $2,140,760     $2,106,215
                                                             ==========     ==========

See Notes to Consolidated Financial Statements.

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


              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIAREIS

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                  Six Months Ended

                                    June 30,

                                                                2000           1999
                                                                ----           ----
                                                                   (in thousands)

OPERATING ACTIVITIES:
<S>                                                           <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 26,449       $ 33,506
  Adjustments for Non-Cash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    57,310         54,337
    Deferred Income Taxes. . . . . . . . . . . . . . . . . .    10,575         (7,018)
    Deferred Investment Tax Credits  . . . . . . . . . . . .    (2,241)        (2,282)
  Changes in Certain Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .     8,375        (19,190)
    Fuel Inventory . . . . . . . . . . . . . . . . . . . . .    (6,342)       (20,547)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    29,989         (8,263)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (8,474)        17,614
    Fuel Recovery. . . . . . . . . . . . . . . . . . . . . .   (18,218)           419
    Other Current Liabilities. . . . . . . . . . . . . . . .     3,892          1,629
    Other Deferred Credits . . . . . . . . . . . . . . . . .   (29,236)         5,317
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .    (1,008)          (497)
                                                              --------       --------
        Net Cash Flows From Operating Activities . . . . . .    71,071         55,025
                                                              --------       --------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (61,879)       (45,989)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .    (4,338)          (596)
                                                              --------       --------
        Net Cash Flows Used For Investing Activities . . . .   (66,217)       (46,585)
                                                              --------       --------

FINANCING ACTIVITIES:
  Redemption of Preferred Stock. . . . . . . . . . . . . . .        (1)            (1)
  Proceeds from Issuance of Long-term Debt . . . . . . . . .   149,367           -
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (45,450)        (1,635)
  Changes in Advances from Affiliates. . . . . . . . . . . .   (77,655)        46,649
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (31,000)       (54,000)
  Dividends Paid on Preferred Stock. . . . . . . . . . . . .      (119)          (114)
                                                              --------       --------
        Net Cash Flows Used For Financing Activities . . . .    (4,858)        (9,101)
                                                              --------       --------

Net Decrease in Cash and Cash Equivalents. . . . . . . . . .        (4)          (661)
Cash and Cash Equivalents at Beginning of Period . . . . . .     2,018          4,444
                                                              --------       --------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  2,014       $  3,783
                                                              ========       ========


Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $20,711,000  and
  $26,152,000  and for income taxes was  $14,270,000 and $18,031,000 in 2000 and
  1999, respectively.

See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>

              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                  JUNE 30, 2000

                                   (UNAUDITED)

1.      GENERAL

        The accompanying  unaudited  consolidated financial statements should be
read in  conjunction  with the Company's  1999 Form 10-K.  Certain  prior-period
amounts have been reclassified to conform to current-period presentation. In the
opinion  of  management,   the  financial  statements  reflect  all  adjustments
(consisting of only normal  recurring  accruals)  which are necessary for a fair
presentation of the results of operations for interim periods.

2.      MERGER

        In June 2000 the merger of American  Electric  Power  Company,  Inc. and
Central and South West Corporation,  the parent company of Southwestern Electric
Power Company, was completed. As part of the change in control, an adjustment to
conform the  Company's  accounting  for  vacation  pay  accruals  with  American
Electric Power's accounting policy was necessary.

        The  effect of the  conforming  change in  accounting  was to reduce net
assets by $4.5  million  at  December  31,  1999 and  reduce  net income by $0.6
million for the three  months  ended March 31, 2000 and by $0.2 million and $0.8
million for the three months and six months ended June 30, 1999, respectively.

        In  connection  with the  merger,  the  regulatory  commissions  for the
Company's retail jurisdictions approved settlement agreements that provides for,
among other things, sharing net merger savings with customers over five to eight
year periods after  consummation of the merger through rate reduction  riders or
credits.  In the event that  actual net  merger  savings  are less than the rate
reductions, results of operations and cash flows will be adversely affected.

3.       TEXAS AND ARKANSAS RESTRUCTURING

         In June  1999  legislation  was  signed  into  law in Texas  that  will
restructure  the  electric  utility  industry  (Texas  Legislation).  The  Texas
Legislation, among other things:

o gives  customers of  investor-owned  utilities the opportunity to choose their
electric  provider  beginning  January 1, 2002;

o provides  for the  recovery  of  regulatory  assets and other  stranded  costs
through securitization and non-bypassable wires charges;

o requires  reductions in nitrogen  oxide and sulfur  dioxide  emissions;

o provides a rate freeze  until January  1, 2002  followed  by a 6% rate
reduction  for  residential  and small commercial customers, an additional rate
reduction for low-income customers and a number of customer protections;

o sets an earnings test for the three years of rate freeze (1999 through  2001);

o sets  certain  limits for  ownership  and  control of  generation  capacity by
companies; and

o    requires a filing after January 10, 2004 to finalize  stranded  costs (2004
     true-up  proceeding)  including  final fuel recovery  balances,  regulatory
     assets, certain environmental costs,  accumulated excess earnings and other
     issues.

     Delivery of electricity will continue to be the responsibility of the local
electric transmission and distribution utility company at regulated prices. Each
electric  utility must submit a plan to unbundle its business  activities into a
retail electric  provider,  a power  generation  company and a transmission  and
distribution utility.

     In  1999   legislation   was  enacted  in  Arkansas  that  will  ultimately
restructure the electric utility industry (Arkansas  Legislation).  Major points
of the Arkansas Legislation are:

o        Retail  competition  begins  January 1, 2002 but can be delayed until
as late as June 30, 2003 by the Arkansas  Public Service Commission
(Arkansas Commission).

o    Transmission  facilities must be operated by an independent system operator
     if owned by a company which also owns generation assets.

o        Rates will be frozen for one to three years.

o Market power issues will be addressed by the Arkansas Commission.

     The Company filed a business rate  unbundling  plan in Arkansas on June 30,
2000.

     The Company and its affiliated  electric  utilities  which operate in Texas
filed  their  business  separation  (unbundling)  plan with the  Public  Utility
Commission of Texas (Texas Commission) on January 10, 2000. The filing described
a financial and accounting  functional  separation but not a legal or structural
separation,  described  how  operations  will be  physically  separated  and the
functions they will perform, described competitive energy services, and provided
a  code  of  conduct.  In  March  2000  the  Texas  Commission  ruled  that  the
subsidiaries'  plans  were not in  compliance  with the  Texas  Legislation  and
ordered revised plans be submitted to separate the generation  business from the
wires  business in  separate  legal  entities by January 1, 2002.  In May 2000 a
revised separation plan was filed,  which the Texas Commission  approved on July
7, 2000 in an interim order.

         The Company's  financial  statements  have  historically  reflected the
effects of applying  the  requirements  of  Statement  of  Financial  Accounting
Standards   (SFAS)  71,   "Accounting  for  the  Effects  of  Certain  Types  of
Regulation".  Pursuant to those requirements,  regulatory assets and liabilities
had been recorded to reflect the economic effect of cost-based regulation.  When
a company  determines  that its operations or a segment of its operations are no
longer cost-based rate regulated, it is required to apply the provisions of SFAS
101 "Accounting for the Discontinuance of Application of Statement 71". Pursuant
to those requirements and further guidance provided in the Financial  Accounting
Standards  Board's  Emerging  Issues Task Force  (EITF)  Issue 97-4, a regulated
entity is required to write-off  regulatory  assets and  liabilities  related to
operations  that are no longer  cost-based  regulated,  unless  recovery of such
amounts is provided  through  rates to be  collected  in a portion of the entity
operations  which  continues to be  regulated.  Additionally,  it is required to
determine if any plant assets are impaired under SFAS 121,  "Accounting  for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of."

         As a result of the  scheduled  deregulation  of generation in Texas and
Arkansas, the application of SFAS 71 for the generation portion of the Company's
business in those state was  discontinued  in 1999.  Since the Company  does not
expect to be able to recover  generation-related  regulatory  assets,  they were
written off in 1999.

         An  impairment  analysis  for  generation  assets  under  SFAS  121 was
completed  which  concluded  there was no  accounting  impairment  of generation
assets at the time the  company  ceased  application  of SFAS 71. An  impairment
analysis  involves  estimating  future net cash flows arising from the use of an
asset.  If the  undiscounted  net cash  flows  exceed  the net book value of the
asset,  then there is no impairment of the asset for  accounting  purposes.  The
Company  will test its  generation  assets  for  impairment  under SFAS 121 when
circumstances change.

         The Texas  Legislation  also  provides  that each year  during the 1999
through 2001 rate freeze period,  electric  utilities are subject to an earnings
test. For electric  utilities  without  stranded costs any earnings in excess of
the  most  recently  approved  cost of  capital  in its  last  rate  case or the
statutorily mandated 9.6% in SWEPCo's situation since it has not had a rate case
since 1992 must either flow back to customers or make capital  expenditures,  at
no charge to customers, to improve transmission or distribution facilities or to
improve air quality.  As a result,  the Company  established a liability of $2.1
million  for the 1999  estimated  effect  of the  earnings  cap  under the Texas
Legislation.  The Texas  Commission is required  under the Texas  Legislation to
certify that the Company's calculation of excess earnings for 1999 is correct by
September  30, 2000.  The Company  must  dispose of the  liability by the end of
2000.

        Beginning  January  1,  2002,  fuel  costs  will not be subject to Texas
Commission fuel reconciliation proceedings.  Consequently, the Company will file
a final fuel  reconciliation  with the Texas  Commission  which reconciles their
fuel costs through the period ending  December 31, 2001. Any final fuel balances
will be included in the 2004 true-up proceeding.

4.       FINANCING ACTIVITIES

        In March 2000, the Company sold $150 million of unsecured  floating rate
notes.  The notes have a two-year  final  maturity of March 1, 2002,  but may be
redeemed at par after one year.  The interest  rate will reset  quarterly at the
then current  three-month  London Inter-Bank  Overnight Rate (LIBOR) plus 0.23%.
The initial rate set March 1, 2000 was 6.34%.  Net proceeds of $149 million were
used to refund $45 million of first mortgage bonds maturing April 1, 2000 and to
repay a portion of outstanding short-term indebtedness.

        The Company has in the past, and may in the future,  acquire outstanding
debt and preferred stock securities in open market transactions.

5.       CONTINGENCIES

Lignite Mining Agreement Litigation

        The Company and Central  Louisiana  Electric  Company,  Inc. (CLECO) are
each a 50% owner of Dolet  Hills  Power  Station  Unit 1 and jointly own lignite
reserves in the Dolet Hills area of northwestern Louisiana. In 1982, the Company
and CLECO entered into a lignite  mining  agreement  with the Dolet Hills Mining
Venture  (DHMV),  a  partnership  for the mining and  delivery of lignite from a
portion of these reserves.

        In April 1997,  the Company and CLECO sued DHMV and its partners in U.S.
District Court for the Western District of Louisiana  seeking to enforce various
obligations of DHMV under the lignite  mining  agreement,  including  provisions
relating to the quality of  delivered  lignite,  pricing,  and mine  reclamation
practices.  In June 1997,  DHMV filed an answer  denying the  allegations in the
suit and filed a counterclaim asserting various  contract-related claims against
the  Company  and  CLECO.  The  Company  and CLECO have  denied the  allegations
contained in the  counterclaims.  In January 1999, the Company and CLECO amended
the claims against DHMV to include a request that the lignite  mining  agreement
be terminated.

        In April 2000, the parties agreed to settle the  litigation.  As part of
the settlement,  DHMV's  interest in the mining  operations and related debt and
other  obligations  will be purchased by the Company and CLECO. The closing date
for the  settlement  is December 31, 2000.  The court has stayed the  litigation
until  January  2001 to give  the  parties  time to  consummate  the  settlement
agreement.

        Management  believes that the  resolution of this matter will not have a
material effect on the Company's results of operations,  cash flows or financial
condition.

NOx Reductions

        On April 19, 2000, the Texas Natural  Resource  Conservation  Commission
adopted  regulations  that require  reductions in nitrogen oxide (NOx) emissions
for existing permitted electric generating  facilities in the East Texas Region.
The Company's implementation date for the regulations is 2005.

        Preliminary  estimates  indicate that compliance with the NOx rule could
result in required capital  expenditures of  approximately  $151 million for the
Company.  Since compliance costs cannot be estimated with certainty,  the actual
cost to comply could be significantly  different than the Company's  preliminary
estimate  depending  upon  the  compliance   alternatives  selected  to  achieve
reductions in NOx emissions. Unless the depreciation of such costs are recovered
from customers  through  regulated  rates and/or  reflected in the future market
price of electricity  when generation is deregulated,  they will have an adverse
effect on future  results  of  operations,  cash  flows and  possibly  financial
condition.

Other

        The Company  continues to be involved in other matters  discussed in its
1999 Form 10-K.


<PAGE>



              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                            AND FINANCIAL CONDITION
 ------------------------------------------------------------------------------

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND

                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

         SWEPCO's net income was $2.6 million, or 12%, lower for the quarter and
was $7.1  million,  or 21%,  lower for the six months ended June 30,  2000.  The
decreases  resulted  primarily  from increased  operating  expenses and interest
charges.

        Income statement line items which changed significantly were:

                                    Increase (Decrease)

                           Second Quarter     Year-to-Date

                           (in millions)   %  (in millions)   %

Operating Revenues . . . .     $ 30       12      $ 45       10
Fuel Expense . . . . . . .       22       24        35       21
Purchased Power. . . . . .        9       82        14       85
Other Operation Expense. .        4       12         8       12
Maintenance Expense. . . .       (1)      (5)        1        3
Taxes Other Than Federal
  Income Taxes . . . . . .       (3)     (20)       (9)     (28)
Federal Income Taxes . . .       (1)     (14)       (3)     (24)
Interest Charges . . . . .        1        6         2        6

         The increase in operating  revenues  resulted  from higher fuel related
revenues due to increased  fuel and purchased  power expenses and an increase in
retail energy sales.  Energy sales to retail  customers  increased 4% and 2% for
the quarter and year-to-date  periods,  respectively,  reflecting an increase in
average customer usage.

         Fuel expense increased due primarily to an increase in the average unit
cost of fuel as a result  of  higher  spot  market  natural  gas  prices  and an
increase in generation to meet the increased retail demand for electricity.

         The increase in purchased  power  expenses was  primarily  caused by an
increase in firm  energy  contract  purchases,  increased  capacity  charges and
increased economy energy purchases to meet the increased retail demand.

        Other operation expenses were higher due primarily to increased customer
accounts  expenses,  increased  insurance  expenses,  increased employee related
expenses due to a change in the method of accruing  vacation  pay and  increased
regulatory and consulting expenses for a sales tax audit.

     A reduction in generating station maintenance  activity caused the decrease
in maintenance  expenses in the second quarter.  Depreciation  and  amortization
expenses  increased  due  to  changes  in  depreciation  rates  associated  with
rate-related  settlements  in Arkansas and  Louisiana  in 1999.

     The decrease in taxes other than federal income taxes was due to a decrease
in ad valorem taxes and  franchise  taxes.  The decline in federal  income taxes
attributable  to  operations  is the result of a decline in pre-tax book income.

Interest  expense on  long-term  debt  increased  as a result of the issuance of
unsecured floating rate notes in March 2000.

Interest  on  short-term  borrowings  for the six  months  ended  June 30,  2000
increased  $1.1 million due  primarily  to increases in the average  outstanding
balance of short-term borrowings.

FINANCIAL CONDITION

         Total plant and property additions for the year to date period were $62
million.

         In March 2000, the Company sold $150 million of unsecured floating rate
notes.  The notes have a two-year  final  maturity of March 1, 2002,  but may be
redeemed at par after one year.  The interest  rate will reset  quarterly at the
then current  three-month  London Inter-Bank  Overnight Rate (LIBOR) plus 0.23%.
The initial rate set March 1, 2000 was 6.34%.  Net proceeds of $149 million were
used to refund $45 million of first mortgage bonds maturing April 1, 2000 and to
repay a portion of outstanding short-term indebtedness.

        The Company has in the past, and may in the future,  acquire outstanding
debt and preferred stock securities in open market transactions.

MARKET RISKS

         The  Company  has  certain   market  risks  inherent  in  its  business
activities  from changes in interest  rates.  Market risk represents the risk of
loss that may impact the Company due to adverse changes in interest rates.

         The exposure to changes in interest rates from the Company's short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.

OTHER MATTERS

NOx Reductions

        On April 19, 2000, the Texas Natural  Resource  Conservation  Commission
adopted  regulations  that require  reductions in nitrogen oxide (NOx) emissions
for existing permitted electric generating  facilities in the East Texas Region.
The Company's implementation date for the regulations is 2005.

        Preliminary  estimates  indicate that compliance with the NOx rule could
result in required capital  expenditures of  approximately  $151 million for the
Company.  Since compliance costs cannot be estimated with certainty,  the actual
cost to comply could be significantly  different than the Company's  preliminary
estimate  depending  upon  the  compliance   alternatives  selected  to  achieve
reductions in NOx emissions. Unless the depreciation of such costs are recovered
from customers  through  regulated  rates and/or  reflected in the future market
price of electricity  when generation is deregulated,  they will have an adverse
effect on future  results  of  operations,  cash  flows and  possibly  financial
condition.


<PAGE>
<TABLE>
<CAPTION>


                          WEST TEXAS UTILITIES COMPANY

                              STATEMENTS OF INCOME

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           -------------------    --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)

<S>                                        <C>        <C>          <C>        <C>
OPERATING REVENUES . . . . . . . . . . .   $130,742   $107,782     $227,277   $188,834
                                           --------   --------     --------   --------
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .     47,207     29,208       75,787     52,343
  Purchased Power. . . . . . . . . . . .     22,455     12,474       37,348     20,768
  Other Operation. . . . . . . . . . . .     15,751     20,364       36,055     41,075
  Maintenance. . . . . . . . . . . . . .      5,045      6,282        9,907     10,460
  Depreciation and Amortization. . . . .     11,292     10,850       22,533     21,624
  Taxes Other Than Federal Income Taxes.      6,653      7,097       11,616     14,585
  Federal Income Taxes . . . . . . . . .      5,401      5,146        7,312      4,696
                                           --------   --------    ---------   --------

          TOTAL OPERATING EXPENSES . . .    113,804     91,421      200,558    165,551
                                           --------   --------    ---------   --------

OPERATING INCOME . . . . . . . . . . . .     16,938     16,361       26,719     23,283

NONOPERATING INCOME (LOSS) . . . . . . .     (3,149)        55       (3,239)       172
                                           --------   --------    ---------   --------

INCOME BEFORE INTEREST CHARGES . . . . .     13,789     16,416       23,480     23,455

INTEREST CHARGES . . . . . . . . . . . .      5,719      6,300       11,577     12,407
                                           --------   --------     --------   --------

NET INCOME . . . . . . . . . . . . . . .      8,070     10,116       11,903     11,048

PREFERRED STOCK DIVIDENDS REQUIREMENTS .         26         26           52         52
                                           --------   --------     --------   --------

EARNINGS APPLICABLE TO COMMON STOCK. . .   $  8,044   $ 10,090     $ 11,851   $ 10,996
                                           ========   ========     ========   ========

                         STATEMENTS OF RETAINED EARNINGS

                                   (UNAUDITED)

                                           Three Months Ended       Six Months Ended

                                                June 30,                June 30,
                                           ------------------     --------------
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD
  AS PREVIOUSLY REPORTED. . . .. . . . .   $115,515  $111,470     $115,856    $117,189
CONFORMING CHANGE IN ACCOUNTING POLICY .     (2,966)   (2,624)      (2,614)     (2,249)
                                           --------  --------     --------    --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD.    112,549   108,846      113,242     114,940

NET INCOME . . . . . . . . . . . . . . .      8,070    10,116       11,903      11,048

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .      4,500     7,000        9,000      14,000
    Preferred Stock. . . . . . . . . . .         26        26           52          52
                                           --------  --------     --------    --------

BALANCE AT END OF PERIOD . . . . . . . .   $116,093  $111,936     $116,093    $111,936
                                           ========  ========     ========    ========

The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Financial Statements.

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


                          WEST TEXAS UTILITIES COMPANY

                                 BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                          <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .  $  426,968     $  429,783
  Transmission. . . . . . . . . . . . . . . . . . . . . . .     230,340        220,479
  Distribution. . . . . . . . . . . . . . . . . . . . . . .     408,805        403,206
  General . . . . . . . . . . . . . . . . . . . . . . . . .     110,123        113,945
  Construction Work in Progress . . . . . . . . . . . . . .      26,944         15,131
                                                             ----------     ----------
          Total Electric Utility Plant. . . . . . . . . . .   1,203,180      1,182,544
  Accumulated Depreciation. . . . . . . . . . . . . . . . .     502,328        495,847
                                                             ----------     ----------
          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .     700,852        686,697
                                                             ----------     ----------

OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . .      22,372         21,570
                                                             ----------     ----------

CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .       4,065          3,810
  Accounts Receivable:
    Customers . . . . . . . . . . . . . . . . . . . . . . .      34,031         45,742
    Affiliated Companies. . . . . . . . . . . . . . . . . .       7,904          4,837
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .      12,912         17,133
  Materials and Supplies. . . . . . . . . . . . . . . . . .      12,568         14,029
  Under-recovered Fuel Costs. . . . . . . . . . . . . . . .      20,007         14,652
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .       4,468          2,883
                                                             ----------     ----------

          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .      95,955        103,086
                                                             ----------     ----------

REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .       9,220         16,687
                                                             ----------     ----------

DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      11,449         20,108
                                                             ----------     ----------

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $  839,848     $  848,148
                                                             ==========     ==========

See Notes to Financial Statements.

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


                          WEST TEXAS UTILITIES COMPANY

                                 BALANCE SHEETS

                                   (UNAUDITED)

                                                              June 30,     December 31,
                                                                2000           1999
                                                              --------     --------
                                                                   (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $25 Par Value:
    Authorized - 7,800,000 Shares

<S>                                                          <C>            <C>
    Outstanding - 5,488,560 Shares. . . . . . . . . . . . .  $  137,214     $  137,214
  Paid-in Capital . . . . . . . . . . . . . . . . . . . . .       2,236          2,236
  Retained Earnings . . . . . . . . . . . . . . . . . . . .     116,093        113,242
                                                             ----------     ----------
          Total Common Shareholder's Equity . . . . . . . .     255,543        252,692

Preferred Stock . . . . . . . . . . . . . . . . . . . . . .       2,482          2,482
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . .     263,760        263,686
                                                             ----------     ----------

          TOTAL CAPITALIZATION. . . . . . . . . . . . . . .     521,785        518,860
                                                             ----------     ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .        -            40,000
  Advances from Affiliates. . . . . . . . . . . . . . . . .      40,456         21,408
  Accounts Payable - General. . . . . . . . . . . . . . . .      47,167         39,611
  Accounts Payable - Affiliated Companies . . . . . . . . .      23,841         19,770
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      10,477         12,458
  Interest Accrued. . . . . . . . . . . . . . . . . . . . .       4,701          4,165
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      12,437         13,906
                                                             ----------     ----------

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     139,079        151,318
                                                             ----------     ----------

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     147,204        148,992
                                                             ----------     ----------

INVESTMENT TAX CREDITS. . . . . . . . . . . . . . . . . . .      24,687         25,323
                                                             ----------     ----------

DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . .       7,093          3,655
                                                             ----------     ----------

CONTINGENCIES (Note 5)

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $  839,848     $  848,148
                                                             ==========     ==========

See Notes to Financial Statements.

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


                          WEST TEXAS UTILITIES COMPANY

                            STATEMENTS OF CASH FLOWS

                                   (UNAUDITED)

                                                                  Six Months Ended

                                    June 30,

                                                                2000           1999
                                                                ----           ----
                                                                   (in thousands)

OPERATING ACTIVITIES:
<S>                                                           <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 11,903       $ 11,048
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    22,959         22,086
    Deferred Income Taxes. . . . . . . . . . . . . . . . . .    (2,138)          (263)
    Investment Tax Credits . . . . . . . . . . . . . . . . .      (636)          (637)
  Changes in Assets and Liabilities:
    Accounts Receivable. . . . . . . . . . . . . . . . . . .     8,644          9,580
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     5,682           (722)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    11,627          4,511
    Accrued Taxes. . . . . . . . . . . . . . . . . . . . . .    (1,981)        (1,189)
    Fuel Recovery. . . . . . . . . . . . . . . . . . . . . .    (5,355)        (1,042)
    Other. . . . . . . . . . . . . . . . . . . . . . . . . .    13,905            270
                                                              --------       --------
        Net Cash Flows From Operating Activities . . . . . .    64,610         43,642
                                                              --------       --------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (32,470)       (25,527)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .    (1,878)        (2,295)
                                                              --------       --------
        Net Cash Flows Used For Financing Activities . . . .   (34,348)       (27,822)
                                                              --------       --------

FINANCING ACTIVITIES:
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (40,000)          -
  Change in Advances from Affiliates (net) . . . . . . . . .    19,048          4,536
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (9,000)       (14,000)
  Dividends Paid on Preferred Stock. . . . . . . . . . . . .       (55)           (52)
                                                              --------       --------
        Net Cash Flows Used For Financing Activities . . . .   (30,007)        (9,516)
                                                              --------       --------

Net Increase in Cash and Cash Equivalents. . . . . . . . . .       255          6,304
Cash and Cash Equivalents at Beginning of Period . . . . . .     3,810          2,093
                                                              --------       --------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  4,065       $  8,397
                                                              ========       ========


Supplemental Disclosure:
  Cash  paid  for  interest  net  of  capitalized  amounts  was  $9,053,000  and
  $9,022,000  and for income taxes was  $5,442,000  and  $4,589,000  in 2000 and
  1999, respectively.

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


                          WEST TEXAS UTILITIES COMPANY

                          NOTES TO FINANCIAL STATEMENTS

                                  JUNE 30, 2000

                                   (UNAUDITED)

1.      GENERAL

        The  accompanying  unaudited  financial  statements  should  be  read in
conjunction with the Company's 1999 Form 10-K. Certain prior-period amounts have
been reclassified to conform to current-period  presentation.  In the opinion of
management, the financial statements reflect all adjustments (consisting of only
normal  recurring  accruals) which are necessary for a fair  presentation of the
results of operations for interim periods.

2.      MERGER

         In June 2000 the merger of American  Electric Power  Company,  Inc. and
Central and South West  Corporation,  the parent company of West Texas Utilities
Company,  was  completed.  As part of the change in control,  an  adjustment  to
conform the  Company's  accounting  for  vacation  pay  accruals  with  American
Electric Power's accounting policy was necessary.

        The  effect of the  conforming  change in  accounting  was to reduce net
assets by $2.6  million  at  December  31,  1999 and  reduce  net income by $0.4
million for the three  months  ended March 31, 2000 and by $0.2 million and $0.6
million for the three months and six months ended June 30, 1999, respectively.

         In  connection  with  the  merger,  the  Texas  Commission  approved  a
settlement  agreement that provides for, among other things,  sharing net merger
savings with customers over six years after  consummation  of the merger through
rate reduction riders. In the event that actual net merger savings are less than
the  rate  reduction  riders,  results  of  operations  and cash  flows  will be
adversely affected.

3.       TEXAS RESTRUCTURING

    In 1999  legislation was signed into law in Texas that will  restructure the
electric  utility industry (Texas  Legislation).  The Texas  Legislation,  among
other things:

o    gives  customers of  investor-owned  utilities the  opportunity to choose
     their electric provider beginning January 1, 2002;
o    provides for the recovery of  regulatory  assets and other  stranded  costs
     through  securitization  and  non-bypassable  wires charges;

o        requires reductions in nitrogen oxide and sulfur dioxide emissions;

o    provides  a rate  freeze  until  January  1,  2002  followed  by a 6%  rate
     reduction for residential  and small  commercial  customers,  an additional
     rate  reduction  for   low-income   customers  and  a  number  of  customer
     protections;

o    sets an earnings  test for the three years of rate freeze  (1999  through
     2001);

o    sets certain limits for ownership and control of generation capacity by
     companies; and

o    requires a filing after January 10, 2004 to finalize  stranded  costs (2004
     true-up  proceeding)  including  final fuel recovery  balances,  regulatory
     assets, certain environmental costs,  accumulated excess earnings and other
     issues.

     Delivery of electricity will continue to be the responsibility of the local
regulated electric  transmission and distribution utility company. Each electric
utility  must submit a plan to unbundle its  business  activities  into a retail
electric   provider,   a  power  generation   company  and  a  transmission  and
distribution utility.

     The Company and its affiliated  electric  utilities  which operate in Texas
filed their joint business separation  (unbundling) plan with the Public Utility
Commission of Texas (Texas Commission) on January 10, 2000. The filing described
a financial and accounting  functional  separation but not a legal or structural
separation,  described  how  operations  will be  physically  separated  and the
functions they will perform, described competitive energy services, and provided
a code  of  conduct.  In  March  2000,  the  Texas  Commission  ruled  that  the
subsidiaries'  plans  were not in  compliance  with the  Texas  Legislation  and
ordered revised plans be submitted to separate the generation  business from the
wires  business in  separate  legal  entities by January 1, 2002.  In May 2000 a
revised separation plan was filed,  which the Texas Commission  approved on July
7, 2000 in an interim order.

     The Company's financial statements have historically  reflected the effects
of applying the  requirements  of Statement  of Financial  Accounting  Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of Regulation". Pursuant
to those  requirements,  regulatory  assets and liabilities had been recorded to
reflect the economic effect of cost-based regulation.  When a company determines
that its operations or a segment of its operations are no longer cost-based rate
regulated,  it is required to apply the provisions of SFAS 101  "Accounting  for
the   Discontinuance   of  Application  of  Statement  71".  Pursuant  to  those
requirements and further guidance provided in the Financial Accounting Standards
Board's  Emerging  Issues Task Force (EITF) Issue 97-4, a company is required to
write-off  regulatory assets and liabilities related to deregulated  operations,
unless  recovery of such amounts is provided  through rates to be collected in a
portion  of  the  company's   operations   which   continues  to  be  regulated.
Additionally, it is required to determine if any plant assets are impaired under
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of."

         As a result of the scheduled  deregulation of generation in Texas,  the
application  of  SFAS  71  for  the  generation  portion  of  the  business  was
discontinued  in 1999.  Since the Company  does not expect to be able to recover
generation-related regulatory assets, they were written off in 1999.

     An impairment  analysis for generation  assets under SFAS 121 was completed
which concluded there was no accounting  impairment of generation  assets at the
time the Company ceased application of SFAS 71. An impairment  analysis involves
estimating  future  net cash  flows  arising  from the use of an  asset.  If the
undiscounted  net cash flows exceed the net book value of the asset,  then there
is no impairment of the asset for accounting purposes. The Company will test its
generation assets for impairment under SFAS 121 when circumstances change.

         The Texas  Legislation  also  provides  that each year  during the 1999
through 2001 rate freeze period,  electric  utilities are subject to an earnings
test. For electric  utilities  without  stranded costs any earnings in excess of
the most  recently  approved  cost of capital in its last rate case must  either
flow back to customers or make capital expenditures,  at no charge to customers,
to improve transmission or distribution facilities or to improve air quality. As
a result,  the  Company  established  a liability  of $2.8  million for the 1999
estimated  effect of the  earnings  cap under the Texas  Legislation.  The Texas
Commission is required under the Texas Legislation to certify that the Company's
calculation  of excess  earnings for 1999 is correct by September 30, 2000.  The
Company must dispose of the liability by the end of 2000.

        Beginning  January  1,  2002,  fuel  costs  will not be subject to Texas
Commission fuel reconciliation proceedings.  Consequently, the Company will file
its final fuel  reconciliation  with the Texas  Commission  which reconciles its
fuel costs through the period ending  December 31, 2001. Any final fuel balances
will be included in the 2004 true-up proceeding.

4.      FINANCING ACTIVITIES

        In April 2000 the Company  retired $40 million of Series T, 7-1/2% first
mortgage bonds at maturity.

        The Company has in the past, and may in the future,  acquire outstanding
debt and preferred stock securities in open market transactions.

5.      CONTINGENCIES

        The Company  continues  to be involved in matters  discussed in its 1999
Form 10-K.


<PAGE>



                          WEST TEXAS UTILITIES COMPANY

          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                             AND FINANCIAL CONDITION

                   SECOND QUARTER 2000 vs. SECOND QUARTER 1999
                                       AND

                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

         Net income  decreased $2 million to $8.1 million for the second quarter
of 2000 and  increased  $0.9  million to $11.9  million for the six months ended
June 30, 2000. A decrease in other operation  expenses and interest expenses was
mostly offset by a loss  incurred in the second  quarter with the phasing out of
merchandise sales.

        Income statement line items which changed significantly were:

                                     Increase (Decrease)

                            Second Quarter     Year-to-Date

                            (in millions)   %  (in millions)   %

Operating Revenues . . . . .    $ 23       21      $38        20
Fuel Expense . . . . . . . .      18       62       23        45
Purchased Power Expense. . .      10       80       17        80
Other Operation Expense. . .      (5)     (23)      (5)      (12)
Taxes Other Than Federal
  Income Taxes . . . . . . .       -        -       (3)      (20)
Federal Income Taxes . . . .       -        -        3        56
Nonoperating Income. . . . .      (3)     N.M.      (3)      N.M.
Interest Charges . . . . . .      (1)      (9)      (1)       (7)

N.M. = Not Meaningful

         Operating  revenues  increased  due in part to  increased  fuel-related
revenues due primarily to higher fuel and purchased  power expenses as discussed
below.  Due to the operation of a fuel clause  mechanism in Texas,  revenues are
accrued to reflect fuel cost increases. Non-fuel revenues increased $6.6 million
for the year-to-date period as a result of increased retail sales resulting from
favorable  weather  conditions  and a true-up  adjustment  under the final  1999
earnings cap filing required by the Texas Legislation.

         The increase in fuel expense was due to a rise in the average unit fuel
costs resulting from an increase in the spot market price of natural gas.

         Purchased  power expense  increased due primarily to increased  economy
energy purchases.


<PAGE>


         Other  Operation  expenses  decreased  due  primarily to a reduction in
transmission expenses that resulted from new prices for the Electric Reliability
Council of Texas (ERCOT)  transmission  grid.  Each year ERCOT  establishes  new
rates to allocate the costs of the Texas  transmission  system to Texas electric
utilities.  The lower transmission  expense was partially offset by increases in
generation  expense related to drought  related  conditions,  outside  services,
regulatory services, and a change in the method of recording vacation expense.

         Taxes other than federal income taxes  decreased due primarily to lower
         ad valorem and state franchise taxes. Federal income taxes attributable
         to operations increased due primarily to increased income. Nonoperating
         income decreased due primarily to the termination of merchandise  sales
         and the costs of phasing out these sales. Interest charges decreased as
         a result of reduction in long-term borrowings.

        FINANCIAL CONDITION

        Total plant and property  additions for the year to date period were $32
        million.  In April 2000 the  Company  retired  $40  million of Series T,
        7-1/2% first mortgage bonds at maturity.

         The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.

MARKET RISKS

         The  Company  has  certain   market  risks  inherent  in  its  business
activities  from changes in interest  rates.  Market risk represents the risk of
loss that may impact the Company due to adverse changes in interest rates.

         The exposure to changes in interest rates from the Company's short-term
and long-term  borrowings at June 30, 2000 is not  materially  different than at
December 31, 1999.


<PAGE>


                           PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.

American Electric Power Company, Inc. ("AEP")

        A discussion  of litigation  regarding the Cook Nuclear Plant  appearing
under the caption "Shareholders'  Litigation" in Part I - Note 9."Contingencies"
is incorporated by reference herein.
<TABLE>
<CAPTION>

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

AEP

        The annual meeting of shareholders  was held in Columbus,  Ohio on April
26, 2000. The holders of shares entitled to vote at the meeting or their proxies
cast votes at the  meeting  with  respect to the  following  three  matters,  as
indicated below:

        1.     Election of nine  directors  to hold office until the next annual
               meeting and until their successors are duly elected. Each nominee
               for director received the votes of shareholders as follows:

                                                         Number of Shares                  Number of

                       Nominee                               Voted For                 Votes Withheld

<S>                                                          <C>                           <C>
               John P. DesBarres                             154,751,346                   3,670,260
               E. Linn Draper, Jr.                           154,730,659                   3,690,947
               Robert W. Fri                                 154,701,286                   3,720,320
               Lester A. Hudson, Jr.                         154,730,472                   3,691,134
               Leonard J. Kujawa                             154,684,336                   3,737,270
               Donald G. Smith                               154,765,861                   3,655,745
               Linda Gillespie Stuntz                        154,732,029                   3,689,577
               Kathryn D. Sullivan                           154,625,005                   3,796,601
               Morris Tanenbaum                              154,584,762                   3,836,844
               Ronald Marsico                                     34,295

        2.     Approve the appointment by the Board of Directors of Deloitte & Touche LLP as
               independent auditors of AEP for the year 2000.
               The proposal was approved by a vote of the shareholders as follows:

               Votes FOR                                     153,696,363
               Votes AGAINST                                   1,250,752
               Votes ABSTAINED                                 3,474,491
               Broker NON-VOTES*                                       0

        3.     Approve the AEP 2000 Long-Term Incentive Plan.
               The proposal was approved by a vote of the shareholders as follows:

               Votes FOR                                     140,505,343
               Votes AGAINST                                  14,430,621
               Votes ABSTAINED                                 3,485,642
               Broker NON-VOTES*                                       0

                              *A non-vote  occurs when a nominee  holding shares
for a beneficial owner votes on one proposal, but does

        not  vote  on  another  proposal  because  the  nominee  does  not  have
        discretionary  voting power and has not received  instructions  from the
        beneficial owner.
</TABLE>

Appalachian Power Company ("APCo")

        The  annual  meeting  of  stockholders  was held on April 25,  2000 at 1
Riverside Plaza, Columbus, Ohio. At the meeting,  13,499,500 votes were cast FOR
each of the  following  five persons for election as directors and there were no
votes  withheld and such  persons were elected  directors to hold office for one
year or until their successors are elected and qualify:

               E. Linn Draper, Jr.                        Armando A. Pena
               Henry W. Fayne                             Joseph H. Vipperman
               William J. Lhota

        No other business was transacted at the meeting.

Indiana Michigan Power Company ("I&M")

        The  annual  meeting  of  stockholders  was held on April 25,  2000 at 1
Riverside Plaza, Columbus,  Ohio. At the meeting,  1,400,000 votes were cast FOR
each of the following twelve persons for election as directors and there were no
votes  withheld and such  persons were elected  directors to hold office for one
year or until their successors are elected and qualify:

               Karl G. Boyd                                  Armando A. Pena
               E. Linn Draper, Jr.                           John R. Sampson
               Jeffrey A. Drozda                             David B. Synowiec
               Henry W. Fayne                                Joseph H. Vipperman
               William J. Lhota                              William E. Walters
               Mark W. Marano                                Earl H. Wittkamper

        No other business was transacted at the meeting.

Ohio Power Company ("OPCo")

        The  annual  meeting  of  shareholders  was  held  on May 2,  2000  at 1
Riverside Plaza, Columbus, Ohio. At the meeting,  27,952,473 votes were cast FOR
each of the  following  five persons for election as directors and there were no
votes  withheld and such  persons were elected  directors to hold office for one
year or until their successors are elected and qualify:

               E. Linn Draper, Jr.                           Armando A. Pena
               Henry W. Fayne                                Joseph H. Vipperman
               William J. Lhota

        No other business was transacted at the meeting.

Item 5.  Other Information.

AEP, AEP Generating  Company  ("AEGCo"),  APCo,  Columbus Southern Power Company
("CSPCo"), I&M, Kentucky Power Company ("KEPCo") and OPCo

        Reference  is made to pages 29 and 30 of the Annual  Report on Form 10-K
for the year ended  December  31, 1999  ("1999  10-K") for a  discussion  of the
remand of the federal ozone and particulate  matter National Ambient Air Quality
Standards by the U.S. Court of Appeals for the District of Columbia Circuit.  In
May 2000,  the U.S.  Supreme Court granted  petitions of the U.S.  Environmental
Protection  Agency,  several  states and the U.S.  Chamber of  Commerce  seeking
review of the Circuit Court's opinion.

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

        (a)    Exhibits:

        APCo, Central Power and Light Company ("CPL"),  CSPCo, I&M, KEPCo, OPCo,
        Public Service Company of Oklahoma ("PSO"),  Southwestern Electric Power
        Company ("SWEPCo") and West Texas Utilities Company ("WTU")

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

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

               Exhibit 27 - Financial Data Schedule.

        (b)    Reports on Form 8-K:

        Companies Reporting  Date of Report Items Reported

        AEP, CSPCo and OPCo  May 8, 2000    Item 5. Other Events

                                            Item 7. Financial Statements and
                                                      Exhibits
        AEP                 June 15, 2000  Item 2. Acquisition or Disposition of
                                                   Assets

                                           Item 7. Financial Statements and
                                                   Exhibits




        AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo
                            June 15, 2000
                                            Item 5. Other Events

                                            Item 7. Financial Statements and
                                                    Exhibits

        CPL, PSO, SWEPCo and WTU
                 June 15, 2000              Item 1. Changes in Control of
                                                     Registrant


<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/Leonard V. Assante
            ----------------------         ---------------------
                  Armando A. Pena              Leonard V. Assante
                  Treasurer                    Deputy Controller



                             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/Leonard V. Assante
            -----------------------        ---------------------
                  Armando A. Pena              Leonard V. Assante
                  Vice President and           Deputy Controller
                  Treasurer



Date: August 11, 2000