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

<TABLE>

                     SECURITIES AND EXCHANGE COMMISSION
                          WASHINGTON, D.C.  20549

                                 FORM 10-Q

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

               For The Quarterly Period Ended MARCH 31, 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.
  <S>           <C>                                                     <C>
  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

  1-2680        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

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>
    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                               FORM 10-Q

                 For The Quarter Ended March 31, 2000
<CAPTION>
                                 INDEX

                                                                          Page
Part I.  FINANCIAL INFORMATION
           <S>                                                            <C>
           American Electric Power Company, Inc. and Subsidiary Companies:
             Consolidated Statements of Income and
               Statements of Comprehensive Income . . . . . . . . . . . . A-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2 - A-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4
             Consolidated Statements of Retained Earnings . . . . . . . . A-5
             Notes to Consolidated Financial Statements . . . . . . . . . A-6 - A-18
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . A-19- A-32

           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
             Management's Narrative Analysis of Results of Operations . . B-6 - B-7

           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-20

           Columbus Southern Power Company and Subsidiaries:
             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-10
             Management's Narrative Analysis of Results of Operations . . D-11- D-12

           Indiana Michigan 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-8
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . E-9 - E-15

           Kentucky Power Company:
             Statements of Income and Statements of Retained Earnings . . F-1
             Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-2 - F-3
             Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-4
             Notes to Financial Statements. . . . . . . . . . . . . . . . F-5 - F-7
             Management's Narrative Analysis of Results of Operations . . F-8 - F-9
</TABLE>


<PAGE>
<PAGE>
<TABLE>
                                    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                                        FORM 10-Q

                                    For The Quarter Ended March 31, 2000
<CAPTION>
                                          INDEX

                                                                        Page
           <S>                                                          <C>
           Ohio Power Company and Subsidiaries:
             Consolidated Statements of Income and
               Consolidated Statements of Retained Earnings . . . . . . G-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . G-2 - G-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . G-4
             Notes to Consolidated Financial Statements . . . . . . . . G-5 - G-10
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . G-11- G-18


Part II. OTHER INFORMATION

           Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1
           Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-2

SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3




   This combined Form 10-Q is separately filed by American Electric Power Company,
Inc., AEP Generating Company, Appalachian Power Company, Columbus Southern Power
Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company.
Information contained herein relating to any individual registrant is filed by such
registrant on its own behalf.  Each registrant makes no representation as to
information relating to the other registrants.
</TABLE>


<PAGE>
<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 impact of the proposed merger with CSW including any regulatory
           conditions imposed on the merger or the inability to consummate the
           merger with CSW.
           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 nuclear plant which is on an
           extended
           safety related shutdown.
           Problems or failures related to Year 2000 readiness of computer
           software and hardware.
           Inflationary trends.
           Electricity and gas market prices.
           Interest rates
           Other risks and unforeseen events.



<PAGE>
<PAGE>
<TABLE>
    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                   CONSOLIDATED STATEMENTS OF INCOME
                (in millions, except per-share amounts)
                              (UNAUDITED)
<CAPTION>
                                                              Three Months Ended
                                                                   March 31,
                                                              2000           1999
<S>                                                          <C>            <C>
REVENUES:
  Domestic Regulated Electric Utilities. . . . . . . . . .   $1,546         $1,550
  Worldwide Non-regulated Electric and Gas Operations. . .      200            144

          TOTAL REVENUES . . . . . . . . . . . . . . . . .    1,746          1,694

EXPENSES:
  Fuel and Purchased Power . . . . . . . . . . . . . . . .      511            491
  Maintenance and Other Operation. . . . . . . . . . . . .      489            427
  Depreciation and Amortization. . . . . . . . . . . . . .      154            148
  Taxes Other Than Income Taxes. . . . . . . . . . . . . .      125            124
  Worldwide Non-regulated Electric and Gas Operations. . .      164            127

         TOTAL EXPENSES. . . . . . . . . . . . . . . . . .    1,443          1,317

OPERATING INCOME . . . . . . . . . . . . . . . . . . . . .      303            377
OTHER INCOME (LOSS), net . . . . . . . . . . . . . . . . .        3             (1)
INCOME BEFORE INTEREST, PREFERRED DIVIDENDS
  AND INCOME TAXES . . . . . . . . . . . . . . . . . . . .      306            376
INTEREST AND PREFERRED DIVIDENDS . . . . . . . . . . . . .      139            132
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . .      167            244
INCOME TAXES . . . . . . . . . . . . . . . . . . . . . . .       63             93
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .   $  104         $  151
AVERAGE NUMBER OF SHARES OUTSTANDING . . . . . . . . . . .      194            192
EARNINGS PER SHARE . . . . . . . . . . . . . . . . . . . .    $0.53          $0.79
CASH DIVIDENDS PAID PER SHARE. . . . . . . . . . . . . . .    $0.60          $0.60



            CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                              (UNAUDITED)
                                                              Three Months Ended
                                                                   March 31,
                                                              2000           1999
                                                                 (in millions)

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .  $  104          $  151

OTHER COMPREHENSIVE INCOME (LOSS):
  Foreign Currency Translation
    Adjustment . . . . . . . . . . . . . . . . . . . . . .     (22)             -

COMPREHENSIVE INCOME . . . . . . . . . . . . . . . . . . .   $  82          $  151

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                           March 31,    December 31,
                                                             2000           1999
                                                               (in millions)
ASSETS
<S>                                                          <C>            <C>
CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .       $   364        $   333
  Accounts Receivable (net). . . . . . . . . . . . . .           993            910
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .           260            307
  Materials and Supplies . . . . . . . . . . . . . . .           311            311
  Accrued Utility Revenues . . . . . . . . . . . . . .           204            246
  Energy Trading Contracts . . . . . . . . . . . . . .         1,327          1,001
  Prepayments and Other. . . . . . . . . . . . . . . .           116            108

          TOTAL CURRENT ASSETS . . . . . . . . . . . .         3,575          3,216

PROPERTY, PLANT AND EQUIPMENT:
  Electric:
      Production . . . . . . . . . . . . . . . . . . .         9,984          9,949
      Transmission . . . . . . . . . . . . . . . . . .         3,831          3,832
      Distribution . . . . . . . . . . . . . . . . . .         5,536          5,536
  Other (including gas and coal mining assets
   and nuclear fuel) . . . . . . . . . . . . . . . . .         2,364          2,307
  Construction Work in Progress. . . . . . . . . . . .           558            581
          Total Property, Plant and Equipment. . . . .        22,273         22,205
  Accumulated Depreciation and Amortization. . . . . .         9,254          9,150

          NET PROPERTY, PLANT AND EQUIPMENT. . . . . .        13,019         13,055


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         2,202          2,171



OTHER ASSETS . . . . . . . . . . . . . . . . . . . . .         3,106          3,046



            TOTAL. . . . . . . . . . . . . . . . . . .       $21,902        $21,488

See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                          March 31,    December 31,
                                                              2000          1999
                                                                 (in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S>                                                         <C>            <C>
CURRENT LIABILITIES:
  Accounts Payable . . . . . . . . . . . . . . . . . .      $   729        $   699
  Short-term Debt. . . . . . . . . . . . . . . . . . .        1,118            888
  Long-term Debt Due Within One Year . . . . . . . . .          978          1,111
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .          416            414
  Interest Accrued . . . . . . . . . . . . . . . . . .          114             78
  Obligations Under Capital Leases . . . . . . . . . .          127             91
  Energy Trading Contracts . . . . . . . . . . . . . .        1,203            964
  Other. . . . . . . . . . . . . . . . . . . . . . . .          445            425

          TOTAL CURRENT LIABILITIES. . . . . . . . . .        5,130          4,670

LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . .        6,239          6,336

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .        2,664          2,745

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .          321            326

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .          210            213

DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . .          716            517

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        1,487          1,511

CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . .          163            164

CONTINGENCIES (Note 9)

COMMON SHAREHOLDERS' EQUITY
  Common Stock-Par Value $6.50:
                                 2000         1999
    Shares Authorized . . . .600,000,000   600,000,000
    Shares Issued . . . . . .203,103,341   203,103,341
    (8,999,992 shares were held in treasury) . . . . .      $ 1,320       $ 1,320
  Paid-in Capital. . . . . . . . . . . . . . . . . . .        1,932         1,932
  Accumulated Other Comprehensive Income(Loss)
    Foreign Currency Translation Adjustments . . . . .           (8)           14
  Retained Earnings. . . . . . . . . . . . . . . . . .        1,728         1,740

          TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . .        4,972         5,006

            TOTAL. . . . . . . . . . . . . . . . . . .      $21,902       $21,488

See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                 CONSOLIDATED STATEMENTS OF CASH FLOWS
                              (UNAUDITED)
<CAPTION>
                                                                Three Months Ended
                                                                    March 31,
                                                                 2000         1999
                                                                   (in millions)
<S>                                                              <C>          <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .     $ 104        $ 151
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .       195          172
    Deferred Federal Income Taxes. . . . . . . . . . . . . .       (23)          30
    Deferred Investment Tax Credits. . . . . . . . . . . . .        (5)          (6)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .       (84)          25
    Fuel, Materials and Supplies . . . . . . . . . . . . . .        47          (48)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .        39           31
    Prepayments. . . . . . . . . . . . . . . . . . . . . . .       (12)         (42)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .        34          123
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .         2            5
    Interest Accrued . . . . . . . . . . . . . . . . . . . .        36           42
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .        37           37
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .       (82)        (117)
        Net Cash Flows From Operating Activities . . . . . .       288          403

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .      (186)        (212)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .       (11)          (5)
        Net Cash Flows Used For Investing Activities . . . .      (197)        (217)

FINANCING ACTIVITIES:
  Issuance of Common Stock . . . . . . . . . . . . . . . . .         -           31
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .        10            7
  Change in Short-term Debt (net). . . . . . . . . . . . . .       230            9
  Retirement of Long-term Debt . . . . . . . . . . . . . . .      (184)         (11)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .      (116)        (115)
        Net Cash Flows Used For Financing Activities . . . .       (60)         (79)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .        31          107
Cash and Cash Equivalents at Beginning of Period . . . . . .       333          173
Cash and Cash Equivalents at End of Period . . . . . . . . .     $ 364        $ 280

Supplemental Disclosure:
  Cash paid for interest net of  capitalized amounts was $98 million and $84 million
  and for income taxes was $22 million and $3 million in 2000 and 1999,
  respectively.  Noncash acquisitions under capital leases were $17 million and $18
  million in 2000 and 1999, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)
<CAPTION>
                                                              Three Months Ended
                                                                   March 31,
                                                              2000           1999
                                                                 (in millions)
<S>                                                         <C>             <C>
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . .  $1,740          $1,684

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .     104             151

DEDUCTIONS:
  Cash Dividends Declared. . . . . . . . . . . . . . . . .     116             115

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . .  $1,728          $1,720

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
  AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                          MARCH 31, 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 ACTIVITIES

        In the first quarter of 2000 subsidiaries retired $180
   million principal amount of long-term debt and issued $10
   million of long-term debt.

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 MW Cook Plant is owned
   and operated by the Company's subsidiary, Indiana Michigan
   Power Company (I&M).

        In February 2000, I&M was notified by the NRC that the
   Confirmatory Action Letter had been closed.  Closing of the
   Confirmatory Action Letter is one of the key approvals needed
   to restart the nuclear units.  The  Confirmatory Action Letter
   was issued in September 1997 requiring I&M to address certain
   issues identified in the letter.

        Progress to restart the units continues.  Refueling of Unit
   2, the first unit scheduled to restart, was completed on April
   14, 2000.  The NRC's final Unit 2 pre-restart inspection began
   on May 8, 2000, which coincided with the reactor heat-up of
   Unit 2 and the return to operational service of common plant
   systems.  When testing and other work required for restart are
   complete, I&M will seek concurrence from the NRC to return Unit
   2 to service.  Refueling and maintenance work to restart Unit
   1 will be performed after Unit 2 is returned to service.  Any
   issues or difficulties encountered in testing of equipment as
   part of the restart process could delay the restart of the
   units.

<PAGE>
        Expenditures to restart the Cook units are estimated to
   total approximately $574 million.  Through March 31, 2000, $453
   million has been spent.  In 2000 $80 million of restart costs
   were recorded in other operation and maintenance expense,
   including amortization of $10 million of restart costs
   previously deferred in accordance with settlement agreements
   in the Indiana and Michigan retail jurisdictions.
        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 units are restarted.  The
   amortization of restart costs deferred under Indiana and
   Michigan retail jurisdiction settlement agreements will
   adversely effect results of operations and possibly financial
   condition through 2003 when the amortization period ends.
   Management believes that the Cook units will be successfully
   returned to service.  However, if for some unknown reason the
   units are not returned to service or their return is delayed
   significantly it would have an even greater adverse effect on
   future results of operations, cash flows and financial
   condition.

4. 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 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 the July 30, 1999 order.  Under terms of the
   settlement, AEP will make refunds retroactive to September 7,
   1993 to certain customers affected by the July 30, 1999 FERC
   order.  The refunds will be made in two payments.  The first
   payment was made February 2000 pursuant to  a FERC order
   granting AEP's request to make interim refunds.  The remainder
   is to be paid upon approval by the FERC.  In addition, a new
   lower rate of $1.55 kw/month was made effective January 1,
   2000, for all transmission service customers and a future rate
   of $1.42 kw/month was established to take effect upon the
   consummation of the AEP and Central and South West Corporation
   merger.

   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 of
   approximately 0.5 mills per kwh); annual ENEC recovery
   proceedings are suspended and deferral accounting for over or
   under recovery is discontinued effective January 1, 2000; the
   net cumulative deferred ENEC recovery balance as established
   by a WVPSC order on December 27, 1996, which is $66 million at
   December 31, 1999, shall remain on the books as a regulatory
   liability.  However, if deregulation of generation occurs in
   West Virginia (WV), APCo will use this regulatory liability to
   reduce unrecoverable generation-related regulatory assets and,
   to the extent possible, any additional cost or obligations that
   deregulation may impose.  Also under the Joint Stipulation
   APCo's share of any net savings from the pending merger between
   AEP Co., Inc. and Central and South West Corporation prior to
   December 31, 2004 shall be retained by APCo.  All cost incurred
   in the merger that are allocated to APCo, whether the merger
   is consummated or not, 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.  If 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 a 0.5 mills
   per kwh wires charge in the WV Restructuring Plan (see Note 5
   for discussion of WV Restructuring Plan).

        Because the Joint Stipulation incorporated rate issues that
   will affect customers of Wheeling Power Company, another AEP
   Co., Inc. subsidiary, the WVPSC determined that an opportunity
   for hearing should be given to Wheeling Power's customers
   before taking action on the Joint Stipulation.  As a result
   hearings were held on May 10, 2000.

<PAGE>
5. INDUSTRY RESTRUCTURING

   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 impair-ments and other stranded costs,
   employee severance and retraining costs, consumer education
   costs and other costs.  Stranded costs are generation costs
   that would not be recoverable in a competitive market.

        On March 28, 2000 the PUCO staff issued its report on the
   Company's transition plan filings.  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.  The key provisions of the stipulation agreement
   are:

            Recovery of regulatory assets over seven years for
            Ohio Power Company (OPCo) and eight years for
            Columbus Southern Companies (CSP).
            A shopping incentive of 2.5 mills/kwh for the first
            25% of CSP residential customers that switch
            suppliers.  No shopping incentive for OPCo customers.
            The absorption by CSP and OPCo of 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 companies will make available a fund of up to $10
            million for certain transmission charges imposed by
            PJM and/or a Midwest ISO on generation originating
            in the Midwest ISO or PJM.
            The statutory 5% reduction in the generation component
            of residential tariffs will remain in effect for
            the entire transition period.
            The companies' request for a $90 million gross
            receipts tax rider will be litigated.  Hearings to
            address the gross receipts taxes issue are scheduled
            for May 31, 2000.

        The stipulation agreement is subject to approval by the
   PUCO.  Hearings on the stipulation are scheduled for June 7,
   2000.

   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 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.

   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 provisions of the proposed 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 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
   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 prices paid 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 increased 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.  Currently the Company has a stipulation
   agreement before the WVPSC in connection with a base rate
   filing which provides mechanisms to recover the Company's
   regulatory assets.  The agreement requires the approval of the
   WVPSC.

   Potential For Write Offs In Ohio, Virginia and West Virginia
   Jurisdictions

        Management has concluded that as of March 31, 2000 the
   requirements to apply Statement of Financial Accounting
   Standard (SFAS) No. 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
   in the Ohio, Virginia and West Virginia jurisdictions.  The
   Company's accounting for generation will continue to be in
   accordance with SFAS 71 in the Ohio and Virginia jurisdictions
   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.  The
   establishment of transition rates and wire charges should
   enable management to determine the Company's 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 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 transition plan filings of the
   Company's Ohio jurisdictional electric operating subsidiaries.
   The Ohio Act requires that the PUCO issue its order to approve
   transition plan filings no later than October 31, 2000.  The
   application of SFAS 71 will be discontinued in the Virginia
   retail jurisdictional portion of the Company's generating
   business when the capped rates and the wires charge are known
   in Virginia which is expected to occur by the fourth quarter
   of 2000.  When the effects of implementation of the West
   Virginia restructuring plan are known and measurable, the
   application of SFAS 71 will be discontinued for the West
   Virginia retail jurisdictional portion of the Company's
   generating business.

        Upon the discontinuance of SFAS 71 the Company will have
   to write off its Ohio, Virginia and West Virginia
   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 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.  Absent the determination in the
   legislative or regulatory process of transition rates, any
   wires charge and other pertinent information, it is not
   possible at this time for management to determine if any of the
   Company's generating assets are impaired for accounting
   purposes on an undiscounted cash flow basis.

        The amount of regulatory assets recorded on the books at
   March 31, 2000 applicable to the Ohio, Virginia and West
   Virginia retail jurisdictional generating business is $724
   million, $67 million and $131 million, respectively, 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
   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 and whether the capped transition rates and allowed
   wires charges in Virginia and West Virginia will permit their
   recovery.

        A determination of whether the Company will experience any
   asset impairment loss regarding its Ohio, Virginia and West
   Virginia retail jurisdictional generating assets and any loss
   from a possible inability to recover Ohio, Virginia and West
   Virginia 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 or legislative 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, it could have a material adverse effect on
   results of operations, cash flows and possibly financial
   condition.

6. INVESTMENT IN YORKSHIRE

        The Company has a 50% ownership interest in Yorkshire Power
   Group Limited (Yorkshire) which is accounted for using the
   equity method of accounting.  Equity income in Yorkshire is
   included in revenues from worldwide non-regulated operations.
   The following amounts which are not included in AEP's
   consolidated financial statements represent summarized
   consolidated financial information of total Yorkshire:

<PAGE>
                                          Three Months Ended
                                               March 31,
                                          2000          1999
                                             (in millions)
   Income Statement Data:
     Operating Revenues                 $662.5        $652.0
     Operating Income                    117.1         113.5
     Net Income                           48.3          34.6
<TABLE>
<CAPTION>
7. BUSINESS SEGMENTS

        The Company's principal business segment is its cost based
   rate regulated Domestic Electric Utility business consisting
   of seven regulated utility operating companies providing
   residential, commercial, industrial and wholesale electric
   services in seven Atlantic and Midwestern states.  Also
   included in this segment are the Company's wholesale power
   marketing and trading activities that are conducted as part of
   regulated operations and subject to regulatory ratemaking
   oversight.  The World Wide Electric and Gas Operations segment
   represents principally international investments in energy-related 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.  Other business segments include non-regulated
   electric and gas trading activities,
   telecommunication services, and the marketing of various energy
   saving products and services.  Financial data for the business
   segments for the first quarter of 2000 and 1999 is in the
   following table:

                              Domestic
                              Regulated     Worldwide                 Elimination
                              Electric     Electric and               Reconciling    AEP
                              Utilities   Gas Operations    Other     Adjustments    Consolidated
                                                   (in millions)
<S>                           <C>           <C>            <C>         <C>            <C>
 March 31, 2000
   Revenues from
     external unaffiliated
        customers              $ 1,546       $  236         $(36)        $ -          $ 1,746
   Revenues from
     transactions with other
     operating segments        -              25           67          (92)           -
   Segment net income (loss)     87           24           (7)          -              104
   Total assets              18,596        2,368          938           -           21,902
 March 31, 1999
   Revenues from
     external unaffiliated
        customers                 1,550          148          (4)          -            1,694
   Revenues from
     transactions with other
     operating segments        -              17           31          (48)           -
   Segment net income (loss)    150            8           (7)          -              151
   Total assets              17,440        2,148          542           -           20,130

</TABLE>

<PAGE>
8. MERGER

        As discussed in Note 8 of the Notes to Consolidated
   Financial Statements in the 1999 Annual Report, the Company and
   Central and South West Corporation (CSW) announced plans to
   merge in December 1997.  The appropriate shareholder proposals
   for the consummation of the merger were approved in 1998.  The
   merger agreement was amended to extend the term of the original
   agreement to June 30, 2000 and requires the Company to close
   the merger before that date.

        The merger has received approval from state  regulatory
   commissions in Arkansas, Louisiana, Oklahoma and Texas, the
   four states within CSW's service territory which are required
   to approve the merger.  AEP has reached agreements with its
   state regulatory commission in Indiana, Michigan, Ohio and
   Kentucky regarding merger costs, savings and other merger
   related rate matters.  These AEP service territory state
   commissions have agreed not to oppose the merger in federal
   proceedings.  In addition, the Nuclear Regulatory Commission
   has approved a license transfer application for the transfer
   of control of CSW subsidiary Central Power and Light's South
   Texas Nuclear Plant to the Company and the Department of
   Justice closed its investigation under the Hart-Scott-Rodino
   Antitrust Improvements Act.  Also, in 1998 the Federal Energy
   Regulatory Commission (FERC) issued an order which confirmed
   that a 250 MW firm contract path with the Ameren System was
   available.  The contract path was obtained by  the Company and
   CSW to meet the requirement of the Public Utility Holding
   Company Act of 1935 that the two systems operate on an
   integrated and coordinated basis.

        On March 15, 2000, the FERC conditionally approved the
   merger.  Conditions placed on the merger include:

            The transfer of operational control of AEP's east (the
            current AEP transmission system) and west (the current
            CSW transmission system) transmission systems to a
            fully-functioning, FERC-approved regional transmission
            organization by December 15, 2001, which is the same
            implementation date included in the FERC's general
            order for regional transmission organizations that
            applies to all transmission-owning utilities.
            The independent calculation and posting of available
            transmission capacity to monitor the operation of
            AEP's east transmission system.
            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).  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.  Alternatively, AEP and CSW may choose to
            divest the same or a greater amount of capacity from
            different generating units in their entirety.
            However, such generating units must be of similar
            cost, operation and location characteristics as the
            generating units AEP and CSW originally agreed to
            divest.
            AEP and CSW must complete divestiture of the ERCOT
            capacity by March 15, 2001 and divestiture of the SPP
            capacity by July 1, 2002.

        The FERC found that certain energy sales in SPP and ERCOT
   would be reasonable and effective interim mitigation measures
   until completion of the required SPP and ERCOT divestitures.
   The FERC will require the proposed interim energy sales to be
   in effect when the merger is consummated.

        The Company and CSW submitted a compliance filing to the
   FERC on March 31, 2000.  The filing outlines the companies'
   plans to comply with conditions placed on the merger in the
   commission's March 15 conditional approval.

        The FERC's merger order required the applicants to make the
   compliance filing at least 60 days before consummating the
   merger.

        The two interim transmission - related mitigation measures
   required as a condition for merger approval are to be in place
   until the date that the post-merger AEP east transmission
   system is under operational control of a FERC-approved regional
   transmission organization (RTO).  The conditions and the
   companies's plans to comply are:

        Independent calculation and posting of available trans
   -mission capacity (ATC): AEP has contracted with the SPP to
   perform independent ATC calculation and postings.  The SPP will
   also perform another critical open access same time information
   system (OASIS) function -- the disposing of transmission
   service requests from customers, including marketers affiliated
   with AEP, seeking service over the AEP east transmission zone.

        Independent market monitoring: an independent third party
   will be responsible for reviewing transmission constraint data,
   the effectiveness of redispatch to alleviate such constraints,
   and the impacts of redispatch on the volume and price of energy
   before and after redispatch.

        The merger also requires approval of the SEC.  In October
   1998 AEP and CSW jointly filed an application with the SEC for
   approval of the proposed merger under the Public Utility
   Holding Company Act of 1935.  The SEC merger filing requests
   approval of the merger and related transactions and outlines
   the expected combined company benefits of the merger to the
   Company and CSW customers and shareholders.  Since then, the
   Company and CSW have filed several amendments to the
   application.  Approval of the merger by the SEC is pending.

        As of March 31, 2000, AEP had deferred $47 million of
   incremental costs related to the merger on its consolidated
   balance sheet.  Although consummation of the merger is expected
   to occur in the second quarter of 2000, the Company is unable
   to predict the outcome or the timing of the required regulatory
   proceedings.

9. CONTINGENCIES

   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 March 31, 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.

   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 for the Southern District of
   Ohio that alleges the Company made modifications to generating
   units at certain of its 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.

        Federal EPA also issued Notices of Violation, complaints
   or administrative orders to eight unaffiliated utilities.

        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.  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, the U.S. Court
   of Appeals for the District of Columbia Circuit (Appeals Court)
   issued a decision on March 3, 2000 generally upholding Federal
   EPA's final rule (the NOx rule) that requires substantial
   reductions in nitrogen oxide (NOx) emissions in 22 eastern
   states, including the states in which the Company's generating
   plants are located. A number of utilities, including the
   Company, had filed petitions seeking a review of the final rule
   in the 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.  On
   April 20, 2000, the Company and other industry petitioners
   filed for rehearing of the March 3, 2000 decision including a
   rehearing by the entire Appeals Court.

        Preliminary estimates indicate that compliance with the NOx
   rule upheld by the Appeals Court could result in required
   capital expenditures of approximately $1.6 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 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 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

            FIRST QUARTER 2000 vs. FIRST QUARTER 1999

RESULTS OF OPERATIONS
     Net income declined by $47 million or 31% due predominately to
current expenditures and the amortization of previously deferred
expenditures in the Company's domestic regulated electric utility
operations to prepare the Cook Plant for restart following an
extended outage.  The Cook Plant began an extended outage in
September 1997 when both generating units were shut down because of
questions regarding the operability of certain safety systems.  In
the first quarter of 1999 certain restart expenses were deferred in
accordance with a settlement agreement in Indiana which resolved
all Indiana jurisdictional rate-related issues applicable to the
Cook Plant's extended outage.
     Income statement line items which changed significantly were:
                                       Increase (Decrease)
                                              (in millions)   %

Revenues - Worldwide
 Non-regulated Operations. . . . . . . . . .      $ 56       39
Fuel and Purchased Power Expense . . . . . .        20        4
Maintenance and Other Operation Expense. . .        62       15
Worldwide Non-regulated Operations Expense .        37       29
Income Taxes . . . . . . . . . . . . . . . .       (30)     (32)

     Revenues from Worldwide Non-regulated Operations increased by
39% primarily due to increased natural gas and gas liquid product
prices.  Volumes of natural gas remained consistent with prior year
however prices have increased approximately 50% rebounding from the
depressed market condition in the first quarter of 1999.  The sales
volumes for gas liquids have also increased due to the additional
capacity of a gas processing facility which became operational in
February 1999.
     The increase in fuel and purchased power expense was primarily
attributable to an increase in generation partially offset by
deferral of affiliated mine shutdown costs under the Ohio fuel
clause mechanism. Net generation increased 3% due to increased
availability of generation plant.

<PAGE>
     Maintenance and other operation expense increased significantly
largely as a result of expenditures to prepare the Cook Nuclear
Plant units for restart following an extended Nuclear Regulatory
Commission (NRC) monitored outage which began in September 1997.
     Worldwide Non-regulated Electric and Gas Operations expenses
rose in the current year as prices for natural gas increased
significantly.
     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 current period were $203 million.
     During the first three months of 2000 domestic subsidiaries
issued $10 million principal amount of long-term obligations at an
initial interest rate of 6.305% and retired $180 million amount of
long-term debt with interest rates ranging from 6.35% to 8.40% and
increased short-term debt by $230 million from year-end balances.
OTHER MATTERS
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 MW Cook Plant is owned and operated by the
Company's subsidiary, Indiana Michigan Power Company (I&M).
     In February 2000, I&M was notified by the NRC that the
Confirmatory Action Letter had been closed.  Closing of the
Confirmatory Action Letter is one of the key approvals needed to
restart the nuclear units.  The  Confirmatory Action Letter was
issued in September 1997 requiring I&M to address certain issues
identified in the letter.
     Progress to restart the units continues.  Refueling of Unit 2,
the first unit scheduled to restart, was completed on April 14,
2000.  The NRC's final Unit 2 pre-restart inspection began on May
8, 2000, which coincided with the reactor heat-up of Unit 2 and the
return to operational service of common plant systems.  When
testing and other work required for restart are complete, I&M will
seek concurrence from the NRC to return Unit 2 to service.
Refueling and maintenance work to restart Unit 1 will be performed
after Unit 2 is returned to service.  Any issues or difficulties
encountered in testing of equipment as part of the restart process
could delay the restart of the units.
     Expenditures to restart the Cook units are estimated to total
approximately $574 million.  Through March 31, 2000, $453 million
has been spent.  In 2000 $80 million of restart costs were recorded
in other operation and maintenance expense, including amortization
of $10 million of restart costs previously deferred in accordance
with settlement agreements in the Indiana and Michigan retail
jurisdictions.
     The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations  and cash
flows until the units are restarted.  The amortization of restart
costs deferred under Indiana and Michigan retail jurisdiction
settlement agreements will adversely effect results of operations
and possibly financial condition through 2003 when the amortization
period ends.  Management believes that the Cook units will be
successfully returned to service.  However, if for some unknown
reason the units are not returned to service or their return is
delayed significantly it would have an even greater adverse effect
on future results of operations, cash flows and financial
condition.
Merger
     As discussed in Note 8 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Company and Central and
South West Corporation (CSW) announced plans to merge in December
1997.  The appropriate shareholder proposals for the consummation
of the merger were approved in 1998.  The merger agreement was
amended to extend the term of the original agreement to June 30,
2000 and requires the Company to close the merger before that date.
     The merger has received approval from state  regulatory
commissions in Arkansas, Louisiana, Oklahoma and Texas, the four
states within CSW's service territory which are required to approve
the merger.  AEP has reached agreements with its state regulatory
commission in Indiana, Michigan, Ohio and Kentucky regarding merger
costs, savings and other merger related rate matters.  These AEP
service territory state commissions have agreed not to oppose the
merger in federal proceedings.  In addition, the Nuclear Regulatory
Commission has approved a license transfer application for the
transfer of control of CSW subsidiary Central Power and Light's
South Texas Nuclear Plant to the Company and the Department of
Justice closed its investigation under the Hart-Scott-Rodino
Antitrust Improvements Act.  Also, in 1998 the Federal Energy
Regulatory Commission (FERC) issued an order which confirmed that
a 250 MW firm contract path with the Ameren System was available.
The contract path was obtained by  the Company and CSW to meet the
requirement of the Public Utility Holding Company Act of 1935 that
the two systems operate on an integrated and coordinated basis.
     On March 15, 2000, the FERC conditionally approved the merger.
Conditions placed on the merger include:
          The transfer of operational control of AEP's east (the
          current AEP transmission system) and west (the current CSW
          transmission system) transmission systems to a fully-functioning,
          FERC-approved regional transmission
          organization by December 15, 2001, which is the same
          implementation date included in the FERC's general order
          for regional transmission organizations that applies to
          all transmission-owning utilities.
          The independent calculation and posting of available
          transmission capacity to monitor the operation of AEP's
          east transmission system.
          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).  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.  Alternatively, AEP and CSW
          may choose to divest the same or a greater amount of
          capacity from different generating units in their
          entirety.  However, such generating units must be of
          similar cost, operation and location characteristics as
          the generating units AEP and CSW originally agreed to
          divest.
          AEP and CSW must complete divestiture of the ERCOT
          capacity by March 15, 2001 and divestiture of the SPP
          capacity by July 1, 2002.
     The FERC found that certain energy sales in SPP and ERCOT would
be reasonable and effective interim mitigation measures until
completion of the required SPP and ERCOT divestitures.  The FERC
will require the proposed interim energy sales to be in effect when
the merger is consummated.
     The Company and CSW submitted a compliance filing to the FERC
on March 31, 2000.  The filing outlines the companies' plans to
comply with conditions placed on the merger in the commission's
March 15 conditional approval.
     The FERC's merger order required the applicants to make the
compliance filing at least 60 days before consummating the merger.
     The two interim transmission - related mitigation measures
required as a condition for merger approval are to be in place
until the date that the post-merger AEP east transmission system is
under operational control of a FERC-approved regional transmission
organization (RTO).  The conditions and the companies's plans to
comply are:
     Independent calculation and posting of available trans-mission
capacity (ATC): AEP has contracted with the SPP to perform
independent ATC calculation and postings.  The SPP will also
perform another critical open access same time information system
(OASIS) function -- the disposing of transmission service requests
from customers, including marketers affiliated with AEP, seeking
service over the AEP east transmission zone.
     Independent market monitoring: an independent third party will
be responsible for reviewing transmission constraint data, the
effectiveness of redispatch to alleviate such constraints, and the
impacts of redispatch on the volume and price of energy before and
after redispatch.
     The merger also requires approval of the SEC.  In October 1998
AEP and CSW jointly filed an application with the SEC for approval
of the proposed merger under the Public Utility Holding Company Act
of 1935.  The SEC merger filing requests approval of the merger and
related transactions and outlines the expected combined company
benefits of the merger to the Company and CSW customers and
shareholders.  Since then, the Company and CSW have filed several
amendments to the application.  Approval of the merger by the SEC
is pending.
     As of March 31, 2000, AEP had deferred $47 million of
incremental costs related to the merger on its consolidated balance
sheet.  Although consummation of the merger is expected to occur in
the second quarter of 2000, the Company is unable to predict the
outcome or the timing of the required regulatory proceedings.
Industry Restructuring
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 would not be recoverable in a competitive market.
     On March 28, 2000 the PUCO staff issued its report on the
Company's transition plan filings.  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.  The
key provisions of the stipulation agreement are:
          Recovery of regulatory assets over seven years for
          Ohio Power Company (OPCo)and
          eight years for Columbus Southern Company (CSP).
          A shopping incentive of 2.5 mills/kwh for the first 25% of
          CSP residential customers that switch suppliers.  No
          shopping incentive for OPCo customers.
          The absorption by CSP and OPCo of 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 companies will make available a fund of up to $10
          million for certain transmission charges imposed by PJM and/or
          Midwest ISO on generation originating in the Midwest ISO
          or PJM.
          The statutory 5% reduction in the generation component of
          residential tariffs will remain in effect for the
          entire transition period.
          The companies' request for a $90 million gross receipts
          tax rider will be litigated.  Hearings to address the
          gross receipts tax issue are scheduled for May 31, 2000.
     The stipulation agreement is subject to approval by the PUCO.
Hearings on the stipulation are scheduled for June 7, 2000.
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, on January 1, 2004.
     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 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.
West Virginia Restructuring Plan
     As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Public Service Commission
of West Virginia (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 proposed 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 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 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 prices paid
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
increased 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.  Currently the Company
has a stipulation agreement before the WVPSC in connection with a
base rate filing which provides mechanisms to recovery the
Company's regulatory assets.  The agreement requires the approval
of the WVPSC.
<PAGE>
Potential For Write Offs In Ohio, Virginia and West Virginia
Jurisdictions
     Management has concluded that as of March 31, 2000 the
requirements to apply Statement of Financial Accounting Standard
(SFAS) No. 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 in the Ohio,
Virginia and West Virginia jurisdictions.  The Company's accounting
for generation will continue to be in accordance with SFAS 71 in
the Ohio and Virginia jurisdictions 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.  The establishment of transition rates and
wire charges should enable management to determine the Company's
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 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 transition plan filings for the Company's Ohio
jurisdictional electric operating subsidiaries.  The Ohio Act
requires that the PUCO issue its order to approve transition plan
filings no later than October 31, 2000.  The application of SFAS 71
will be discontinued in the Virginia retail jurisdictional portion
of the Company's generating business when the capped rates and the
wires charge are known in Virginia which is expected to occur by
the fourth quarter of 2000.  When the effects of the West Virginia
restructuring plan are known and measurable, the application of
SFAS 71 will be discontinued for the West Virginia retail
jurisdictional portion of the Company's generating business.
     Upon the discontinuance of SFAS 71 the Company will have to
write off its Ohio, Virginia and West Virginia 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 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.  Absent the determination in the
legislative or regulatory process of transition rates, any wires
charge and other pertinent information, it is not possible at this
time for management to determine if any of the Company's generating
assets are impaired for accounting purposes on an undiscounted cash
flow basis.
     The amount of regulatory assets recorded on the books at March
31, 2000 applicable to the Ohio, Virginia and West Virginia retail
jurisdictional generating business is $724 million, $67 million and
$131 million, respectively, 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
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 request for their
recovery and whether the capped transition rates and allowed wires
charges in Virginia and West Virginia will permit their recovery.
     A determination of whether the Company will experience any
asset impairment loss regarding its Ohio, Virginia and West
Virginia retail jurisdictional generating assets and any loss from
a possible inability to recover Ohio, Virginia and West Virginia
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 or legislative
process.  Should the PUCO or the Virginia SCC fail to approve
transition rates and wires charges that are sufficient to provide
for recovery or it not be possible under the West Virginia
restructuring plan to recover all or a portion 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.
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 March 31,
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.
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 for the Southern District of Ohio that alleges the Company
made modifications to generating units at certain of its 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.
     Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
     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.  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, the U.S. Court of Appeals for
the District of Columbia Circuit (Appeals Court) issued a decision
on March 3, 2000 generally upholding Federal EPA's final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states, including the states in which
the Company's generating plants are located. A number of utilities,
including the Company, had filed petitions seeking a review of the
final rule in the 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.  On April 20, 2000,
the Company and other industry petitioners filed for rehearing of
the March 3, 2000 decision including a rehearing by the entire
Appeals Court.
     Preliminary estimates indicate that compliance with the NOx
rule upheld by the Appeals Court could result in required capital
expenditures of approximately $1.6 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 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.

<PAGE>
Market Risks
     The Company has certain market risks inherent in its business
activities which represent the risk of loss that may impact the
Company due to adverse changes in electricity and gas commodity
prices, foreign currency exchange rates and interest rates.  The
Company's European energy trading operations which commenced in
January 2000 are not material.  The Company's exposure to market
risk from the trading of electricity and natural gas and related
financial derivative instruments has not changed materially since
December 31, 1999.
     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 March 31, 2000 is not
materially different than at December 31, 1999.

<PAGE>
<PAGE>
<TABLE>
                        AEP GENERATING COMPANY
                         STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                                Three Months Ended
                                                                     March 31,
                                                                2000           1999
                                                                  (in thousands)
<S>                                                           <C>            <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . .  $56,866        $52,827

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . .   24,435         20,258
  Rent - Rockport Plant Unit 2 . . . . . . . . . . . . . . .   17,071         17,071
  Other Operation. . . . . . . . . . . . . . . . . . . . . .    3,098          3,370
  Maintenance. . . . . . . . . . . . . . . . . . . . . . . .    2,515          2,262
  Depreciation . . . . . . . . . . . . . . . . . . . . . . .    5,505          5,440
  Taxes Other Than Federal Income Taxes. . . . . . . . . . .    1,126          1,239
  Federal Income Taxes . . . . . . . . . . . . . . . . . . .      721            827

          TOTAL OPERATING EXPENSES . . . . . . . . . . . . .   54,471         50,467

OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . .    2,395          2,360

NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . .      869            856

INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . .    3,264          3,216

INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . .      819            602

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . .  $ 2,445        $ 2,614



                    STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)

                                                                Three Months Ended
                                                                     March 31,
                                                                2000           1999
                                                                   (in thousands)

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

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . .    2,445          2,614

CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . . . . .    1,935          1,073

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . .   $4,183         $4,311



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

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                        AEP GENERATING COMPANY
                            BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                          March 31,     December 31,
                                                            2000            1999
                                                               (in thousands)

ASSETS
<S>                                                       <C>             <C>
ELECTRIC UTILITY PLANT:

  Production. . . . . . . . . . . . . . . . . . . . . .   $631,434        $629,286
  General . . . . . . . . . . . . . . . . . . . . . . .      2,620           2,400
  Construction Work in Progress . . . . . . . . . . . .      5,497           8,407

          Total Electric Utility Plant. . . . . . . . .    639,551         640,093

  Accumulated Depreciation. . . . . . . . . . . . . . .    298,776         295,065


          NET ELECTRIC UTILITY PLANT. . . . . . . . . .    340,775         345,028


CURRENT ASSETS:

  Cash and Cash Equivalents . . . . . . . . . . . . . .      1,706             317
  Accounts Receivable:
    Affiliated Companies. . . . . . . . . . . . . . . .     16,695          22,464
    Miscellaneous . . . . . . . . . . . . . . . . . . .      2,731           2,643
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . .     17,002          17,505
  Materials and Supplies. . . . . . . . . . . . . . . .      4,008           3,966
  Prepayments . . . . . . . . . . . . . . . . . . . . .        116             150


          TOTAL CURRENT ASSETS. . . . . . . . . . . . .     42,258          47,045


REGULATORY ASSETS . . . . . . . . . . . . . . . . . . .      5,684           5,744


DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . .      3,278             823




            TOTAL . . . . . . . . . . . . . . . . . . .   $391,995        $398,640

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                        AEP GENERATING COMPANY
                            BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                          March 31,     December 31,
                                                            2000            1999
                                                               (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                       <C>             <C>
CAPITALIZATION:
  Common Stock - Par Value $1,000:
    Authorized and Outstanding - 1,000 Shares . . . . .   $  1,000        $  1,000
  Paid-in Capital . . . . . . . . . . . . . . . . . . .     27,235          29,235
  Retained Earnings . . . . . . . . . . . . . . . . . .      4,183           3,673
          Total Common Shareholder's Equity . . . . . .     32,418          33,908

          TOTAL CAPITALIZATION. . . . . . . . . . . . .     32,418          33,908

OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . .        534             592

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . .     44,802          44,800
  Short-term Debt - Notes Payable . . . . . . . . . . .      7,050          24,700
  Accounts Payable - General. . . . . . . . . . . . . .      6,068           7,539
  Accounts Payable - Affiliated Companies . . . . . . .     16,236          19,451
  Taxes Accrued . . . . . . . . . . . . . . . . . . . .      8,483           4,285
  Rent Accrued - Rockport Plant Unit 2. . . . . . . . .     23,427           4,963
  Other . . . . . . . . . . . . . . . . . . . . . . . .      2,592           4,763

          TOTAL CURRENT LIABILITIES . . . . . . . . . .    108,658         110,501


DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . .    126,366         127,759

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits . . . . . . . . . . .     62,277          63,114
  Amounts Due to Customers for Income Taxes . . . . . .     25,687          26,266

          TOTAL REGULATORY LIABILITIES. . . . . . . . .     87,964          89,380

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . .     35,705          36,500

DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . .        350            -

CONTINGENCIES (Note 2)

            TOTAL . . . . . . . . . . . . . . . . . . .   $391,995        $398,640

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                        AEP GENERATING COMPANY
                       STATEMENTS OF CASH FLOWS
                              (UNAUDITED)
<CAPTION>
                                                              Three Months Ended
                                                                   March 31,
                                                              2000           1999
                                                                (in thousands)
<S>                                                         <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . .  $  2,445       $  2,614
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . .     5,505          5,440
    Deferred Federal Income Taxes. . . . . . . . . . . . .    (1,374)        (1,339)
    Deferred Investment Tax Credits. . . . . . . . . . . .      (837)          (838)
    Amortization of Deferred Gain on Sale and Leaseback -
      Rockport Plant Unit 2. . . . . . . . . . . . . . . .    (1,393)        (1,393)
    Deferred Property Taxes. . . . . . . . . . . . . . . .    (2,489)        (2,410)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable. . . . . . . . . . . . . . . . . .     5,681          2,700
    Fuel, Materials and Supplies . . . . . . . . . . . . .       461         (7,863)
    Accounts Payable . . . . . . . . . . . . . . . . . . .    (4,686)         4,539
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . .     4,198          5,627
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . .    18,464         18,464
  Other (net). . . . . . . . . . . . . . . . . . . . . . .    (1,735)        (1,045)
        Net Cash Flows From Operating Activities . . . . .    24,240         24,496

INVESTING ACTIVITIES - Net Cash Flows Used
 for Construction. . . . . . . . . . . . . . . . . . . . .    (1,266)          (770)

FINANCING ACTIVITIES:
  Return of Capital to Parent Company. . . . . . . . . . .    (2,000)        (2,000)
  Change in Short-term Debt (net). . . . . . . . . . . . .   (17,650)       (18,875)
  Dividends Paid . . . . . . . . . . . . . . . . . . . . .    (1,935)        (1,073)
        Net Cash Flows Used For Financing Activities . . .   (21,585)       (21,948)

Net Increase (Decrease) in Cash and Cash Equivalents . . .     1,389          1,778
Cash and Cash Equivalents at Beginning of Period . . . . .       317            232
Cash and Cash Equivalents at End of Period . . . . . . . .  $  1,706       $  2,010

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $732,000 and $470,000 in
  2000 and 1999, respectively, and for income taxes was $678,000 in 2000.

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
                        AEP GENERATING COMPANY
                     NOTES TO FINANCIAL STATEMENTS
                             MARCH 31, 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.   CONTINGENCIES

NOx Reductions

     As discussed in Note 3 of the Notes of Financial Statements of the
1999 Annual Report, the U.S. Court of Appeals for the District of
Columbia Circuit (Appeals Court) issued a decision on March 3, 2000
generally upholding the United States Environmental Protection Agency's
final rule (the NOx rule) that requires substantial reductions in
nitrogen oxide (NOx) emissions in 22 eastern states, including the
states in which the AEP System's generating plants are located. A number
of utilities, including the AEP System companies, had filed petitions
seeking a review of the final rule in the 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.  On
April 20, 2000, the AEP System companies and other industry petitioners
filed for rehearing of the March 3, 2000 decision including a rehearing
by the entire Appeals 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

               FIRST QUARTER 2000 vs. FIRST QUARTER 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.
     Although operating revenues increased 8%, net income declined $0.2
million or 6% for the first quarter 2000 as a result of the return of
capital to the parent company in February 1999, May 1999 and March 2000.
     Income statement line items which changed significantly were:

                                        Increase (Decrease)
                                              (in millions)   %

Operating Revenues                                $ 4.0        8
Fuel                                                4.2       21
Other Operation                                    (0.3)      (8)
Maintenance                                         0.3       11
Taxes Other Than Federal Income Taxes              (0.1)      (9)
Federal Income Taxes                               (0.1)     (13)
Interest Charges                                    0.2       36

     The increase in operating revenues resulted from an increase in
generation due to the availability of the Rockport Plant partially
offset by reduced billings for the return on equity component under the
unit power agreements, reflecting the return of capital.  In 1999
planned outages reduced the availability of the Rockport Plant units.
Shorter outages in the first quarter of 2000 allowed the Rockport units
to generate 16% more electricity than in 1999.
     Fuel expense increased due to the increase in generation and a rise
in the average cost of fuel.  The increase in generation is attributable
to the increased availability of the Rockport Plant units.  The rise in
the cost of fuel results from fluctuations in the market price of coal.
Changes in the cost of coal are reflected in the unit power bills and do
not affect net income.
     The decrease in other operation expense is primarily due to a 1999
payment to the City of Rockport in settlement of an annexation issue.
     Although the duration of the planned outages was shorter in 2000
than 1999, the nature of the work performed resulted in more maintenance
expense.
     Taxes other than federal income taxes declined due to a decrease in
taxable income calculated for state taxes.  Federal income taxes
attributable to operations decreased due to a decrease in pre-tax
operating income.
     Interest charges increased due to an increase in average interest
rates on short-term and variable rate debt and an increase in the
average outstanding short-term debt balance reflecting market conditions
for short-term interest rates and the Company's short-term cash demands.

<PAGE>
<PAGE>
<TABLE>
              APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                             Three Months Ended
                                                                  March 31,
                                                             2000           1999
                                                               (in thousands)
<S>                                                         <C>          <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . .  $455,595     $427,702

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . .    98,557      123,573
  Purchased Power. . . . . . . . . . . . . . . . . . . . .    92,564       50,591
  Other Operation. . . . . . . . . . . . . . . . . . . . .    60,641       62,749
  Maintenance. . . . . . . . . . . . . . . . . . . . . . .    28,325       28,511
  Depreciation and Amortization. . . . . . . . . . . . . .    38,338       36,551
  Taxes Other Than Federal Income Taxes. . . . . . . . . .    30,645       29,975
  Federal Income Taxes . . . . . . . . . . . . . . . . . .    28,279       24,145
          TOTAL OPERATING EXPENSES . . . . . . . . . . . .   377,349      356,095
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . .    78,246       71,607
NONOPERATING INCOME (LOSS) . . . . . . . . . . . . . . . .       781       (1,088)
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . .    79,027       70,519
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . .    31,363       31,258
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .    47,664       39,261
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . .       633          675
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . .  $ 47,031     $ 38,586





             CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)
                                                             Three Months Ended
                                                                  March 31,
                                                             2000           1999
                                                               (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . .  $175,854     $179,461
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .    47,664       39,261

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . . . . . . . . . .    31,653       30,348
    Cumulative Preferred Stock . . . . . . . . . . . . . .       525          567
  Capital Stock Expense. . . . . . . . . . . . . . . . . .       108          108

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . .  $191,232     $187,699


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

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
              APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                          March 31,     December 31,
                                                            2000            1999
                                                              (in thousands)
ASSETS
<S>                                                      <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .   $2,027,997      $2,014,968
  Transmission . . . . . . . . . . . . . . . . . . . .    1,155,336       1,151,377
  Distribution . . . . . . . . . . . . . . . . . . . .    1,759,361       1,741,685
  General. . . . . . . . . . . . . . . . . . . . . . .      251,634         247,798
  Construction Work in Progress. . . . . . . . . . . .       94,906         107,123
          Total Electric Utility Plant . . . . . . . .    5,289,234       5,262,951
  Accumulated Depreciation and Amortization. . . . . .    2,104,479       2,079,490

          NET ELECTRIC UTILITY PLANT . . . . . . . . .    3,184,755       3,183,461



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .      189,913         160,546



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .       10,923          64,828
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .      104,867         109,525
    Affiliated Companies . . . . . . . . . . . . . . .       37,470          37,827
    Miscellaneous. . . . . . . . . . . . . . . . . . .        9,254           9,154
    Allowance for Uncollectible Accounts . . . . . . .       (4,697)         (2,609)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .       49,260          58,161
  Materials and Supplies . . . . . . . . . . . . . . .       56,261          56,917
  Accrued Utility Revenues . . . . . . . . . . . . . .       38,120          53,418
  Energy Trading Contracts . . . . . . . . . . . . . .      269,416         143,777
  Prepayments. . . . . . . . . . . . . . . . . . . . .        6,848           7,713

          TOTAL CURRENT ASSETS . . . . . . . . . . . .      577,722         538,711



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .      436,744         436,894



DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .       40,737          34,788

            TOTAL. . . . . . . . . . . . . . . . . . .   $4,429,871      $4,354,400

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
              APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                        March 31,      December 31,
                                                          2000             1999
                                                              (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                    <C>              <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  30,000,000 Shares
    Outstanding - 13,499,500 Shares. . . . . . . . .   $  260,458       $  260,458
  Paid-in Capital. . . . . . . . . . . . . . . . . .      714,434          714,259
  Retained Earnings. . . . . . . . . . . . . . . . .      191,232          175,854
          Total Common Shareholder's Equity. . . . .    1,166,124        1,150,571
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . .       18,260           18,491
    Subject to Mandatory Redemption. . . . . . . . .       20,310           20,310
  Long-term Debt . . . . . . . . . . . . . . . . . .    1,535,052        1,539,302

          TOTAL CAPITALIZATION . . . . . . . . . . .    2,739,746        2,728,674

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . .      124,047          132,130

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . .       48,005          126,005
  Short-term Debt. . . . . . . . . . . . . . . . . .      128,425          123,480
  Accounts Payable - General . . . . . . . . . . . .       43,369           59,150
  Accounts Payable - Affiliated Companies. . . . . .       45,117           42,459
  Taxes Accrued. . . . . . . . . . . . . . . . . . .       65,481           49,038
  Customer Deposits. . . . . . . . . . . . . . . . .       12,764           12,898
  Interest Accrued . . . . . . . . . . . . . . . . .       29,894           19,079
  Energy Trading Contracts . . . . . . . . . . . . .      245,596          140,279
  Other. . . . . . . . . . . . . . . . . . . . . . .       66,761           71,044

          TOTAL CURRENT LIABILITIES. . . . . . . . .      685,412          643,432

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . .      676,645          671,917

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . .       56,093           57,259

DEFERRED CREDITS . . . . . . . . . . . . . . . . . .      147,928          120,988

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . .   $4,429,871       $4,354,400

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
              APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                 CONSOLIDATED STATEMENTS OF CASH FLOWS
                              (UNAUDITED)
<CAPTION>
                                                              Three Months Ended
                                                                   March 31,
                                                              2000          1999
                                                                (in thousands)
<S>                                                        <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . $  47,664     $  39,261
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . .    38,366        36,814
    Deferred Federal Income Taxes. . . . . . . . . . . . .     8,180        12,362
    Deferred Investment Tax Credits. . . . . . . . . . . .    (1,166)       (1,172)
    Deferred Power Supply Costs (net). . . . . . . . . . .    (8,157)       14,706
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . .     7,003        46,450
    Fuel, Materials and Supplies . . . . . . . . . . . . .     9,557        (5,799)
    Accrued Utility Revenues . . . . . . . . . . . . . . .    15,298        10,977
    Prepayments. . . . . . . . . . . . . . . . . . . . . .       865        (6,348)
    Accounts Payable . . . . . . . . . . . . . . . . . . .   (13,123)      (13,802)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . .    16,443        14,702
    Interest Accrued . . . . . . . . . . . . . . . . . . .    10,815         9,298
  Other (net). . . . . . . . . . . . . . . . . . . . . . .   (35,164)      (41,060)

        Net Cash Flows From Operating Activities . . . . .    96,581       116,389


INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . .   (39,901)      (38,129)
  Proceeds from Sale of Property . . . . . . . . . . . . .        16           127

        Net Cash Flows Used For Investing Activities . . .   (39,885)      (38,002)


FINANCING ACTIVITIES:
  Change in Short-term Debt (net). . . . . . . . . . . . .     4,945       (19,125)
  Retirement of Cumulative Preferred Stock . . . . . . . .      (164)           (4)
  Retirement of Long-term Debt . . . . . . . . . . . . . .   (83,201)         -
  Dividends Paid on Common Stock . . . . . . . . . . . . .   (31,653)      (30,348)
  Dividends Paid on Cumulative Preferred Stock . . . . . .      (528)         (567)
        Net Cash Flows Used For Financing Activities . . .  (110,601)      (50,044)

Net Increase (Decrease) in Cash and Cash Equivalents . . .   (53,905)       28,343
Cash and Cash Equivalents at Beginning of Period . . . . .    64,828         7,755
Cash and Cash Equivalents at End of Period . . . . . . . . $  10,923     $  36,098

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $19,610,000 and $21,009,000
  and  for income taxes  was $6,693,000 and  $57,000 in 2000 and 1999, respectively.
  Noncash  acquisitions under capital leases were $3,361,000 and $2,453,000 in 2000
  and 1999, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
            APPALACHIAN POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                          MARCH 31, 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.   FINANCING ACTIVITIES

          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.

3.   RATE MATTERS

     FERC

          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 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 will make refunds retroactive to September 7,
     1993 to certain customers affected by the July 30, 1999 FERC
     order.  The refunds will be made in two payments.  The first
     payment was made February 2000 pursuant to  a FERC order
     granting AEP's request to make interim refunds.  The remainder
     is to be paid upon approval by the FERC.  In addition, a new
     lower rate of $1.55 kw/month was made effective January 1,
     2000, for all transmission service customers and a future rate
     of $1.42 kw/month was established to take effect upon the
     consummation of the AEP and Central and South West Corporation
     merger.

     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, 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 of 0.5 mills
     per kwh); annual ENEC recovery proceedings are suspended and
     deferral accounting for over or under recovery is discontinued
     effective January 1, 2000; and the net cumulative deferred ENEC
     recovery balance as established by a WVPSC order on December
     27, 1996, which is $66 million at December 31, 1999, shall
     remain on the books as a regulatory liability.  If deregulation
     of generation occurs in West Virginia (WV), the Company will
     use this $66 million regulatory liability to reduce
     unrecoverable 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 pending merger
     between AEP Co., Inc. and Central and South West Corporation
     prior to December 31, 2004 shall be retained by the Company.
     All cost incurred in the merger that are allocated to the
     Company, whether the merger is consummated or not, 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.  If
     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 the Company.
     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 adjustments provided in the Joint Stipulation
     and a 0.5 mills per kwh wires charge in the WV Restructuring
     Plan (see Note 4 for discussion of WV Restructuring Plan).

          Because the Joint Stipulation incorporated rate issues that
     will affect customers of Wheeling Power Company, another AEP
     Co., Inc. subsidiary, the WVPSC determined that an opportunity
     for hearing should be given to Wheeling Power's customers
     before taking action on the Joint Stipulation.  Hearings were
     held May 10, 2000.


<PAGE>
4.   RESTRUCTURING

     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 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 the establishment of a wires charge by the fourth
     quarter of 2001.

     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 for West Virginia.  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.  Until the West Virginia legislature makes the
     required tax law changes, the restructuring plan cannot take
     effect.

          The provisions of the proposed 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 generating assets on the
     starting date; functional separation of the generation,
     transmission and distribution businesses on the starting date
     and their legal corporate 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; and establishment of a rate
     stabilization deferral balance of $75.6 million by the end of
     year ten of the transition period to be used as determined by
     the WVPSC to offset prices paid 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 reduced 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.

     Potential For Write Offs In Virginia and West Virginia
     Jurisdictions

          Management has concluded that as of March 31, 2000 the
     requirements to apply Statement of Financial Accounting
     Standard (SFAS) No. 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
     in the Virginia and West Virginia jurisdictions.  The Company's
     accounting for generation will continue to be in accordance
     with SFAS 71 in the Virginia jurisdictions and will continue
     to be considered to be cost-based regulated for accounting
     purposes until the amount of capped rates and stranded cost
     wires charges are determined and known.  The establishment of
     capped rates and wire charges should enable management to
     determine the Company's ability to recover stranded costs
     including regulatory assets and other transition costs, a
     requirement to discontinue application of SFAS 71.  The
     application of SFAS 71 will be discontinued for the Virginia
     retail jurisdictional portion of the Company's generating
     business when the capped rates and the wires charge are known
     in Virginia which is expected to occur by the fourth quarter
     of 2000.  In the West Virginia jurisdiction accounting for
     generation will continue to be in accordance with SFAS 71 and
     the generation business will continue to be considered to be
     cost-based regulated for accounting purposes until the effects
     of implementation of the West Virginia restructuring plan are
     known and measurable.

          Upon the discontinuance of SFAS 71 the Company will have
     to write off its Virginia and West Virginia jurisdictional
     generation-related regulatory assets to the extent that they
     cannot be recovered under the frozen capped rates and stranded
     cost distribution wires charges and record any asset accounting
     impairments.  An impairment loss would be recorded 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.  Absent the
     determination in the legislative or regulatory process of
     transition rates, any wires charge and other pertinent
     information, it is not possible at this time for management to
     determine if any of the Company's generating assets are
     impaired for accounting purposes on an undiscounted cash flow
     basis.

          The amount of regulatory assets recorded on the books at
     March 31, 2000 applicable to the Virginia and West Virginia
     retail jurisdictional generating business is $67 million and
     $131 million, respectively, before related tax effects.  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 capped transition rates and allowed wires
     charges in Virginia and West Virginia will permit their
     recovery and whether the Company can reduce its cost under the
     capped rates.

          A determination of whether the Company will experience any
     asset impairment loss regarding its Virginia and West Virginia
     retail jurisdictional generating assets and any loss from a
     possible inability to recover Virginia and West Virginia
     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 or
     legislative process.  Should the Virginia SCC fail to approve
     transition rates and wires charges that are sufficient to
     provide for recovery or it not be possible under the West
     Virginia restructuring plan to recover all or a portion 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.

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 March 31, 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.

<PAGE>
          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 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.

          Federal EPA also issued Notices of Violation, complaints
     or administrative orders to eight unaffiliated utilities.

          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.  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, unbundled transition period generation
     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, the U.S. Court
     of Appeals for the District of Columbia Circuit (Appeals Court)
     issued a decision on March 3, 2000 generally upholding Federal
     EPA's final rule (the NOx rule) that requires substantial
     reductions in nitrogen oxide (NOx) emissions in 22 eastern
     states, including the states in which the Company's generating
     plants are located. A number of utilities, including the
     Company, had filed petitions seeking a review of the final rule
     in the 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.  On
     April 20, 2000, the AEP System companies and other industry
     petitioners filed for rehearing of the March 3, 2000 decision
     including a rehearing by the entire Appeals Court.

          Preliminary estimates indicate that compliance with the 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 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 its 1999 Annual Report.

<PAGE>
            APPALACHIAN POWER COMPANY AND SUBSIDIARIES
  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                      AND FINANCIAL CONDITION

            FIRST QUARTER 2000 vs. FIRST QUARTER 1999

RESULTS OF OPERATIONS
     Net income increased due to a rise in operating income
reflecting a reduction in fuel costs and an increase in
nonoperating income.  Income statement line items which changed
significantly were:
                                           Increase (Decrease)
                                              (in millions)   %

     Operating Revenues. . . . . . . . . .       $ 27.9        7
     Fuel. . . . . . . . . . . . . . . . .        (25.0)     (20)
     Purchased Power . . . . . . . . . . .         42.0       83
     Federal Income Taxes. . . . . . . . .          4.1       17
     Nonoperating Income . . . . . . . . .          1.9      N.M.

     N.M. = Not Meaningful

     The increases in operating revenues and purchased power expense
reflect 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 cost of fuel and
purchase power expenses from the AEP Power Pool's wholesale sales
to neighboring utilities and marketers.  As a result of an
affiliated company's major industrial customer's decision not to
extend its purchase power agreement, additional power was available
to the AEP Power Pool for sale on the wholesale market providing
the opportunity to increase Power Pool revenues.  The increase in
operating revenues were partially offset by the effect of a
favorable adjustment in 1999 to a provision for revenue refunds in
the Company's Virginia jurisdiction in connection with the payment
of the refund.
     Fuel expense decreased due to a discontinuance of deferral
accounting for the over or under recovery of fuel cost effective
January 1, 2000 as a result of a Joint Stipulation in the Company's
West Virginia jurisdiction.  Fuel costs have declined since
discontinuance of deferral accounting favorably impacting fuel
expense.

<PAGE>
     The increase in federal income tax expense attributable to
operations is primarily due to an increase in pre-tax operating
income.
     Nonoperating income increased due to the favorable effect of
non-regulated power trading transactions outside the AEP Power
Pool's traditional marketing area and the effect of a provision for
loss related to litigation recorded in 1999.
FINANCIAL CONDITION
     Total plant and property additions including capital leases for
the first three months of 2000 were $43 million.  Short-term debt
increased by $5 million during the quarter.
     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.
OTHER MATTERS
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 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 the
establishment of a wires charge by the fourth quarter of 2001.
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 for
West Virginia.  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.  Until the West
Virginia legislature makes the required tax law changes, the
restructuring plan cannot take effect.
     The provisions of the proposed restructuring plan provide for
customer choice of electricity supplier 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 generating
assets on the starting date; functional separation of the
generation, transmission and distribution businesses on the
starting date and their legal corporate 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 choose to 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 stranded cost including net regulatory
assets; and establishment of a rate stabilization deferral balance
of $75.6 million by the end of year ten of the transition period to
be used as determined by the WVPSC to offset prices paid 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 reduced by 1% for
four and a half years, beginning July 1, 2000, and then increase to
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.
Potential For Write Offs In Virginia and West Virginia
Jurisdictions
     Management has concluded that as of March 31, 2000 the
requirements to apply Statement of Financial Accounting Standard
(SFAS) No. 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 in the Virginia
and West Virginia jurisdictions.  The Company's accounting for
generation will continue to be in accordance with SFAS 71 in the
Virginia jurisdictions and will continue to be considered to be
cost-based regulated for accounting purposes until the amount of
capped rates and stranded cost wires charges are determined and
known.  The establishment of capped rates and wire charges should
enable management to determine the Company's ability to recover
stranded costs including regulatory assets and other transition
costs, a requirement to discontinue application of SFAS 71.  The
application of SFAS 71 will be discontinued for the Virginia retail
jurisdictional portion of the Company's generating business when
the capped rates and the wires charge are known in Virginia which
is expected to occur by the fourth quarter of 2000.  In the West
Virginia jurisdiction accounting for generation will continue to be
in accordance with SFAS 71 and the generation business will
continue to be considered to be cost-based regulated for accounting
purposes until the effects of implementation of the West Virginia
restructuring plan are known and measurable.
     Upon the discontinuance of SFAS 71 the Company will have to
write off its Virginia and West Virginia jurisdictional generation-related
regulatory assets to the extent that they cannot be
recovered under the frozen capped rates and stranded costs
distribution wires charges and record any asset accounting
impairments.  An impairment loss would be recorded 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.  Absent the determination in the
legislative or regulatory process of transition rates, wires charge
and other pertinent information, it is not possible at this time
for management to determine if any of the Company's generating
assets are impaired for accounting purposes on an undiscounted cash
flow basis.
     The amount of regulatory assets recorded on the books at March
31, 2000 applicable to the Company's Virginia and West Virginia
retail jurisdictional generating business is $67 million and $131
million, respectively, before related tax effects.  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 capped transition rates and allowed wires charges in
Virginia and West Virginia will permit their recovery and whether
the Company can reduce its cost under the capped rates.
     A determination of whether the Company will experience any
asset impairment loss regarding its Virginia and West Virginia
retail jurisdictional generating assets and any loss from a
possible inability to recover Virginia and West Virginia
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 or legislative
process.  Should the Virginia SCC fail to approve transition rates
and wires charges that are sufficient to enable management to
provide for recovery or should it not be possible under the West
Virginia restructuring plan to recover all or a portion 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.
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 March 31,
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 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.
     Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
     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.  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 energy.

<PAGE>
NOx Reductions
     As discussed in Note 6 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the U.S. Court of Appeals for
the District of Columbia Circuit (Appeals Court) issued a decision
on March 3, 2000 generally upholding Federal EPA's final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states, including the states in which
the Company's generating plants are located. A number of utilities,
including the Company, had filed petitions seeking a review of the
final rule in the 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.  On April 20, 2000,
the AEP System companies and other industry petitioners filed for
rehearing of the March 3, 2000 decision including a rehearing by
the entire Appeals Court.
     Preliminary estimates indicate that compliance with the 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
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 which represent 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 AEP
Power Pool, has not changed materially since December 31, 1999.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at March 31, 2000 is not materially
different than at December 31, 1999.
<PAGE>
<PAGE>
<TABLE>
           COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                               Three Months Ended
                                                                    March 31,
                                                               2000           1999
                                                                  (in thousands)
<S>                                                          <C>            <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $298,306       $279,067

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . .   40,748         45,856
  Purchased Power. . . . . . . . . . . . . . . . . . . . . .   79,703         55,191
  Other Operation. . . . . . . . . . . . . . . . . . . . . .   45,289         45,969
  Maintenance. . . . . . . . . . . . . . . . . . . . . . . .   14,696         13,946
  Depreciation . . . . . . . . . . . . . . . . . . . . . . .   24,544         23,184
  Taxes Other Than Federal Income Taxes. . . . . . . . . . .   31,477         31,078
  Federal Income Taxes . . . . . . . . . . . . . . . . . . .   17,725         17,796

         TOTAL OPERATING EXPENSES. . . . . . . . . . . . . .  254,182        233,020

OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . .   44,124         46,047

NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . .    1,684            361

INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . .   45,808         46,408

INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . .   18,337         18,990

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . .   27,471         27,418

PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . .      533            533

EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . $ 26,938       $ 26,885



             CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)

                                                                Three Months Ended
                                                                     March 31,
                                                                2000          1999
                                                                  (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . $246,584       $186,441

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . .   27,471         27,418

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . . . . . . . . . . .   23,650         21,999
    Cumulative Preferred Stock . . . . . . . . . . . . . . .      437            437
  Capital Stock Expense. . . . . . . . . . . . . . . . . . .       96             96

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . $249,872       $191,327


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

See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
           COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                         March 31,     December 31,
                                                           2000            1999
                                                              (in thousands)
ASSETS
<S>                                                     <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .  $1,553,596      $1,544,858
  Transmission . . . . . . . . . . . . . . . . . . . .     353,410         350,826
  Distribution . . . . . . . . . . . . . . . . . . . .   1,049,831       1,032,550
  General. . . . . . . . . . . . . . . . . . . . . . .     147,786         141,137
  Construction Work in Progress. . . . . . . . . . . .      68,682          82,248
          Total Electric Utility Plant . . . . . . . .   3,173,305       3,151,619
  Accumulated Depreciation . . . . . . . . . . . . . .   1,231,138       1,210,994

          NET ELECTRIC UTILITY PLANT . . . . . . . . .   1,942,167       1,940,625



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .     115,406         101,286



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .       7,451           5,107
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .      66,557          77,418
    Affiliated Companies . . . . . . . . . . . . . . .      17,987          28,453
    Miscellaneous. . . . . . . . . . . . . . . . . . .       5,422           8,887
    Allowance for Uncollectible Accounts . . . . . . .      (2,310)         (3,045)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .      20,284          21,484
  Materials and Supplies . . . . . . . . . . . . . . .      42,807          41,696
  Accrued Utility Revenues . . . . . . . . . . . . . .      40,727          48,117
  Energy Trading Contracts . . . . . . . . . . . . . .     156,270          90,103
  Prepayments. . . . . . . . . . . . . . . . . . . . .      43,518          37,969

          TOTAL CURRENT ASSETS . . . . . . . . . . . .     398,713         356,189



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .     339,968         339,103


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .      55,372          72,787


            TOTAL. . . . . . . . . . . . . . . . . . .  $2,851,626      $2,809,990


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
           COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                       March 31,       December 31,
                                                         2000              1999
                                                             (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                   <C>               <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  24,000,000 Shares
    Outstanding - 16,410,426 Shares. . . . . . . . .  $   41,026        $   41,026
  Paid-in Capital. . . . . . . . . . . . . . . . . .     572,968           572,873
  Retained Earnings. . . . . . . . . . . . . . . . .     249,872           246,584
          Total Common Shareholder's Equity. . . . .     863,866           860,483
  Cumulative Preferred Stock - Subject to
    Mandatory Redemption . . . . . . . . . . . . . .      25,000            25,000
  Long-term Debt . . . . . . . . . . . . . . . . . .     922,690           924,545

          TOTAL CAPITALIZATION . . . . . . . . . . .   1,811,556         1,810,028


OTHER NONCURRENT LIABILITIES . . . . . . . . . . . .      40,857            43,056


CURRENT LIABILITIES:
  Short-term Debt. . . . . . . . . . . . . . . . . .      39,475            45,500
  Accounts Payable - General . . . . . . . . . . . .      24,058            28,279
  Accounts Payable - Affiliated Companies. . . . . .      46,557            52,776
  Taxes Accrued. . . . . . . . . . . . . . . . . . .     113,923           143,477
  Interest Accrued . . . . . . . . . . . . . . . . .      22,636            13,936
  Energy Trading Contracts . . . . . . . . . . . . .     142,453            87,911
  Other. . . . . . . . . . . . . . . . . . . . . . .      33,027            34,375

          TOTAL CURRENT LIABILITIES. . . . . . . . .     422,129           406,254

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . .     448,453           447,607

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . .      43,869            44,716

DEFERRED CREDITS . . . . . . . . . . . . . . . . . .      84,762            58,329

CONTINGENCIES (Note 4)

            TOTAL. . . . . . . . . . . . . . . . . .  $2,851,626        $2,809,990

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
           COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                CONSOLIDATED STATEMENTS OF CASH FLOWS
                              (UNAUDITED)
<CAPTION>
                                                              Three Months Ended
                                                                   March 31,
                                                              2000          1999
                                                                (in thousands)
<S>                                                         <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . .  $ 27,471      $ 27,418
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . .    24,669        23,232
    Deferred Federal Income Taxes. . . . . . . . . . . . .     5,072           (48)
    Deferred Investment Tax Credits. . . . . . . . . . . .      (847)         (868)
    Deferred Fuel Costs (net). . . . . . . . . . . . . . .    (5,408)          836
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . .    24,057        (1,756)
    Fuel, Materials and Supplies . . . . . . . . . . . . .        89         1,616
    Accrued Utility Revenues . . . . . . . . . . . . . . .     7,390         4,484
    Prepayments. . . . . . . . . . . . . . . . . . . . . .    (5,549)       (9,228)
    Accounts Payable . . . . . . . . . . . . . . . . . . .   (10,440)       (7,199)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . .   (29,554)      (13,918)
    Interest Accrued . . . . . . . . . . . . . . . . . . .     8,700         9,939
  Other (net). . . . . . . . . . . . . . . . . . . . . . .    15,474        18,912
        Net Cash Flows From Operating Activities . . . . .    61,124        53,420

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . .   (27,022)      (16,908)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . .       330           246
        Net Cash Flows Used For Investing Activities . . .   (26,692)      (16,662)

FINANCING ACTIVITIES:
  Change in Short-term Debt (net). . . . . . . . . . . . .    (6,025)       (6,800)
  Retirement of Long-term Debt . . . . . . . . . . . . . .    (1,976)         -
  Dividends Paid on Common Stock . . . . . . . . . . . . .   (23,650)      (21,999)
  Dividends Paid on Cumulative Preferred Stock . . . . . .      (437)         (437)
        Net Cash Flows Used For Financing Activities . . .   (32,088)      (29,236)

Net Increase in Cash and Cash Equivalents. . . . . . . . .     2,344         7,522
Cash and Cash Equivalents at Beginning of Period . . . . .     5,107         7,206
Cash and Cash Equivalents at End of Period . . . . . . . .  $  7,451      $ 14,728

Supplemental Disclosure:
  Cash paid for interest net of capitalized  amounts was $8,684,000 and $8,115,000
  and for income taxes was $6,607,000 and $44,000 in 2000 and 1999, respectively.
  Noncash acquisitions  under capital leases were  $1,377,000 and $2,182,000 in 2000
  and 1999, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
           COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                             MARCH 31, 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.   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.

          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 will make
     refunds retroactive to September 7, 1993 to certain customers
     affected by the July 30, 1999 FERC order.  The refunds will be made
     in two payments.  The first payment was made February 2000 pursuant
     to  a FERC order granting AEP's request to make interim refunds.
     The remainder is to be paid upon approval by the FERC.  In addition,
     a new lower rate of $1.55 kw/month was made effective January 1,
     2000, for all transmission service customers and a future rate of
     $1.42 kw/month was established to take effect upon the consummation
     of the AEP and Central and South West Corporation merger.

3.   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 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 would not 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.  The
     key provisions of the stipulation agreement are:

              Recovery of regulatory assets over eight years.
              A shopping incentive 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 for cerain transmission
              charges imposed by PJM and/or Midwest ISO on generation
              originating in the Midwest ISO or PJM.
              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 will be litigated.  Hearings to address the gross
              receipts tax issue are scheduled for May 31, 2000.

          The stipulation agreement is subject to approval by the PUCO.
     Hearings on the stipulation are scheduled for June 7, 2000.

          Management has concluded that as of March 31, 2000 the
     requirements to apply Statement of Financial Accounting Standard
     (SFAS) No. 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 the transition plan
     should 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 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 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 March
     31, 2000 applicable to the Ohio retail jurisdictional generating
     business is $302 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.

          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 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.

4.   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 March 31,
     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

          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.

          Federal EPA also issued Notices of Violation, complaints or
     administrative orders to eight unaffiliated utilities.

          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.  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 U.S. Court of Appeals for
     the District of Columbia Circuit (Appeals Court) issued a decision
     on March 3, 2000 generally upholding Federal EPA's final rule (the
     NOx rule) that requires substantial reductions in nitrogen oxide
     (NOx) emissions in 22 eastern states, including Ohio where the
     Company's generating plants are located. A number of utilities,
     including the Company, had filed petitions seeking a review of the
     final rule in the Appeals Court.  In May 1999, the Appeals Court had
     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.  On April 20, 2000,
     the AEP System companies and other industry petitioners filed for
     rehearing of the March 3, 2000 decision including a rehearing by the
     entire Appeals Court.

          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 the 1999 annual report.

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

               FIRST QUARTER 2000 vs. FIRST QUARTER 1999

     Net income was relatively unchanged in the first quarter as a
decline in operating income was offset by an increase in nonoperating
income and a reduction in interest charges.
     Income statement line items which changed significantly were:

                                             Increase (Decrease)
                                            (in millions)     %

     Operating Revenues . . . . . . . . . . .    $19.2          7
     Fuel . . . . . . . . . . . . . . . . . .     (5.1)       (11)
     Purchased Power. . . . . . . . . . . . .     24.5         44
     Maintenance. . . . . . . . . . . . . . .      0.8          5
     Depreciation . . . . . . . . . . . . . .      1.4          6
     Nonoperating Income. . . . . . . . . . .      1.3        366
     Interest Charges . . . . . . . . . . . .     (0.7)        (3)

     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 sales to neighboring utility systems and power marketers.  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 due to the operation of the fuel clause
adjustment mechanism which resulted in a credit to fuel expense for
underrecovery of emission allowance costs which were deferred as a
regulatory asset.
     Maintenance of distribution and transmission lines accounted for the
increase in maintenance expense.
     Additional investment in distribution plant resulted in the increase
in depreciation expense.

<PAGE>
     The increase in nonoperating income was due to the reversal 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.

<PAGE>
<PAGE>
<TABLE>
            INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                              Three Months Ended
                                                                   March 31,
                                                             2000             1999
                                                                 (in thousands)
<S>                                                        <C>              <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $343,986         $334,113

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . .   47,860           41,800
  Purchased Power. . . . . . . . . . . . . . . . . . . . .   85,106           62,315
  Other Operation. . . . . . . . . . . . . . . . . . . . .  133,551           91,575
  Maintenance. . . . . . . . . . . . . . . . . . . . . . .   55,384           31,202
  Depreciation and Amortization. . . . . . . . . . . . . .   38,211           36,985
  Taxes Other Than Federal Income Taxes. . . . . . . . . .   17,209           19,029
  Federal Income Tax Expense (Credit). . . . . . . . . . .  (18,084)          12,369
          TOTAL OPERATING EXPENSES . . . . . . . . . . . .  359,237          295,275
OPERATING INCOME (LOSS). . . . . . . . . . . . . . . . . .  (15,251)          38,838
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . .      565            1,735
INCOME (LOSS) BEFORE INTEREST CHARGES. . . . . . . . . . .  (14,686)          40,573
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . .   21,867           20,503
NET INCOME (LOSS). . . . . . . . . . . . . . . . . . . . .  (36,553)          20,070
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . .    1,160            1,214
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . $(37,713)        $ 18,856



             CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)

                                                              Three Months Ended
                                                                   March 31,
                                                             2000             1999
                                                                 (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $166,389         $253,154
NET INCOME (LOSS). . . . . . . . . . . . . . . . . . . . .  (36,553)          20,070

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . . . . . . . . . .   26,290           28,664
    Cumulative Preferred Stock . . . . . . . . . . . . . .    1,125            1,182
  Capital Stock Expense. . . . . . . . . . . . . . . . . .       57               32

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $102,364         $243,346

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

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
            INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                            March 31,     December 31,
                                                              2000            1999

                                                                 (in thousands)
ASSETS
<S>                                                       <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,593,200      $2,587,288
  Transmission . . . . . . . . . . . . . . . . . . . .        934,200         928,758
  Distribution . . . . . . . . . . . . . . . . . . . .        826,783         818,697
  General (including nuclear fuel) . . . . . . . . . .        252,702         244,981
  Construction Work in Progress. . . . . . . . . . . .        212,810         190,303
          Total Electric Utility Plant . . . . . . . .      4,819,695       4,770,027
  Accumulated Depreciation and Amortization. . . . . .      2,222,404       2,194,397

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,597,291       2,575,630



NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
  DISPOSAL TRUST FUNDS . . . . . . . . . . . . . . . .        723,697         707,967



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        226,373         213,658



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          8,244           3,863
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         90,706          91,268
    Affiliated Companies . . . . . . . . . . . . . . .         37,655          48,901
    Miscellaneous. . . . . . . . . . . . . . . . . . .         17,516          18,644
    Allowance for Uncollectible Accounts . . . . . . .         (1,622)         (1,848)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         23,720          27,597
  Materials and Supplies . . . . . . . . . . . . . . .         83,417          84,149
  Accrued Utility Revenues . . . . . . . . . . . . . .         41,992          44,428
  Energy Trading Contracts . . . . . . . . . . . . . .        169,876          97,946
  Prepayments. . . . . . . . . . . . . . . . . . . . .         10,205           7,631

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        481,709         422,579


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        598,632         624,810


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         43,072          32,052


            TOTAL. . . . . . . . . . . . . . . . . . .     $4,670,774      $4,576,696

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
            INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                          March 31,       December 31,
                                                            2000              1999
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                     <C>               <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  2,500,000 Shares
    Outstanding - 1,400,000 Shares . . . . . . . . . .   $   56,584        $   56,584
  Paid-in Capital. . . . . . . . . . . . . . . . . . .      732,802           732,739
  Retained Earnings. . . . . . . . . . . . . . . . . .      102,364           166,389
          Total Common Shareholder's Equity. . . . . .      891,750           955,712
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .        8,989             9,248
    Subject to Mandatory Redemption. . . . . . . . . .       64,945            64,945
  Long-term Debt . . . . . . . . . . . . . . . . . . .    1,129,334         1,126,326

          TOTAL CAPITALIZATION . . . . . . . . . . . .    2,095,018         2,156,231

OTHER NONCURRENT LIABILITIES:
  Nuclear Decommissioning. . . . . . . . . . . . . . .      515,587           501,185
  Other. . . . . . . . . . . . . . . . . . . . . . . .      198,129           242,522

          TOTAL OTHER NONCURRENT LIABILITIES . . . . .      713,716           743,707

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .      150,000           198,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .      348,393           224,262
  Accounts Payable - General . . . . . . . . . . . . .       51,533            78,784
  Accounts Payable - Affiliated Companies. . . . . . .       39,437            31,118
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       52,764            48,970
  Interest Accrued . . . . . . . . . . . . . . . . . .       17,101            13,955
  Obligations Under Capital Leases . . . . . . . . . .       47,081            11,072
  Energy Trading Contracts . . . . . . . . . . . . . .      154,856            95,564
  Other. . . . . . . . . . . . . . . . . . . . . . . .      107,891            91,684

          TOTAL CURRENT LIABILITIES. . . . . . . . . .      969,056           793,409

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      609,435           622,157

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .      119,740           121,627

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .       84,079            85,005

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       79,730            54,560

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .   $4,670,774        $4,576,696

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
            INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                 CONSOLIDATED STATEMENTS OF CASH FLOWS
                              (UNAUDITED)
<CAPTION>
                                                               Three Months Ended
                                                                    March 31,
                                                               2000           1999
                                                                 (in thousands)
<S>                                                          <C>            <C>
OPERATING ACTIVITIES:
  Net Income (Loss). . . . . . . . . . . . . . . . . . . . . $(36,553)      $ 20,070
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .   39,191         37,995
    Amortization of Incremental Nuclear
      Refueling Outage Expenses (net). . . . . . . . . . . .    2,035          2,347
    Unrecovered Fuel and Purchased Power Costs . . . . . . .    9,375        (52,664)
    Amortization (Deferral) of Nuclear Outage Costs (net). .   10,000        (30,000)
    Deferred Federal Income Taxes. . . . . . . . . . . . . .   (7,801)         5,365
    Deferred Investment Tax Credits. . . . . . . . . . . . .   (1,887)        (1,898)
    Deferred Property Taxes. . . . . . . . . . . . . . . . .  (10,241)        (9,325)
    Rate Refunds . . . . . . . . . . . . . . . . . . . . . .   (3,740)          -
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .   12,710         (1,247)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    4,609        (15,154)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .    2,436          9,094
    Accounts Payable . . . . . . . . . . . . . . . . . . . .  (18,932)         5,225
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    3,794         14,541
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .   18,464         18,464
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . .    8,296         55,000
    Other Current Liabilities. . . . . . . . . . . . . . . .  (16,095)        14,308
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .   (9,787)        (7,492)
        Net Cash Flows From Operating Activities . . . . . .    5,874         64,629

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .  (51,435)       (30,114)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .      250            903
        Net Cash Flows Used For Investing Activities . . . .  (51,185)       (29,211)

FINANCING ACTIVITIES:
  Change in Short-term Debt (net). . . . . . . . . . . . . .  124,131          1,595
  Retirement of Long-term Debt . . . . . . . . . . . . . . .  (48,000)          -
  Retirement of Cumulative Preferred Stock . . . . . . . . .     (149)            (5)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .  (26,290)       (28,664)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     -            (1,182)
        Net Cash Flows From (Used For) Financing Activities.   49,692        (28,256)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .    4,381          7,162
Cash and Cash Equivalents at Beginning of Period . . . . . .    3,863          5,424
Cash and Cash Equivalents at End of Period . . . . . . . . . $  8,244       $ 12,586

Supplemental Disclosure:
  Cash paid (received) for interest net  of capitalized amounts  was $17,965,000 and
  $18,527,000 in 2000 and 1999, respectively and for income taxes was $(8,966,000)in
  2000.  Noncash acquisitions under capital leases were $1,184,000 and $3,783,000 in
  2000 and 1999, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
         INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                          MARCH 31, 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 March 2000 the Company redeemed at maturity $48 million
   of its 6.40% series of first mortgage bonds.

3. RATE MATTERS

      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 will make refunds retroactive to September 7,
   1993 to certain customers affected by the July 30, 1999 FERC
   order.  The refunds will be made in two payments.  The first
   payment was made February 2000 pursuant to  a FERC order
   granting AEP's request to make interim refunds.  The remainder
   is to be paid upon approval by the FERC.  In addition, a new
   lower rate of $1.55 kw/month was made effective January 1, 2000,
   for all transmission service customers and a future rate of
   $1.42 kw/month was established to take effect upon the
   consummation of the AEP and Central and South West Corporation
   merger.

4. 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.

      In February 2000, the Company was notified by the NRC that
   the Confirmatory Action Letter had been closed.  Closing of the
   Confirmatory Action Letter is one of the key approvals needed
   to restart the nuclear units.  The  Confirmatory Action Letter
   was issued in September 1997 requiring the Company to address
   certain issues identified in the letter.

      Progress to restart the units continues.  Refueling of Unit
   2, the first unit scheduled to restart, was completed on April
   14, 2000.  The NRC's final Unit 2 pre-restart inspection began
   on May 8, 2000, which coincided with the reactor heat-up of Unit
   2 and the return to operational service of common plant systems.
   When testing and other work required for restart are complete,
   the Company will seek concurrence from the NRC to return Unit
   2 to service.  Refueling and maintenance work to restart Unit
   1 will be performed after Unit 2 is returned to service.  Any
   issues or difficulties encountered in testing of equipment as
   part of the restart process could delay the restart of the
   units.

      Expenditures to restart the Cook units are estimated to
   total approximately $574 million.  Through March 31, 2000, $453
   million has been spent.  In 2000 $80 million of restart costs
   were recorded in other operation and maintenance expense,
   including amortization of $10 million of restart costs
   previously deferred in accordance with settlement agreements in
   the Indiana and Michigan retail jurisdictions.

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

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 March 31, 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 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.

      Federal EPA also issued Notices of Violation, complaints or
   administrative orders to eight unaffiliated utilities.

      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.

<PAGE>
      On May 10, 2000, the Company filed motions to dismiss all or
   portions of the complaints.  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 energy.

   NOx Reductions

      As discussed in Note 6 of the Notes to Consolidated
   Financial Statements in the 1999 Annual Report, the U.S. Court
   of Appeals for the District of Columbia Circuit (Appeals Court)
   issued a decision on March 3, 2000 generally upholding Federal
   EPA's final rule (the NOx rule) that requires substantial
   reductions in nitrogen oxide (NOx) emissions in 22 eastern
   states, including the states in which the Company's generating
   plants are located. A number of utilities, including the
   Company, had filed petitions seeking a review of the final rule
   in the 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.  On
   April 20, 2000, the AEP System companies and other industry
   petitioners filed for rehearing of the March 3, 2000 decision
   including a rehearing by the entire Appeals 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 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 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

            FIRST QUARTER 2000 vs. FIRST QUARTER 1999

RESULTS OF OPERATIONS
   The Company reported a loss of $37 million for the first quarter
of 2000 compared with net income of $20 million in 1999.
Expenditures to prepare the Company's two unit Donald C. Cook
Nuclear Plant (Cook Plant) for restart following an extended outage
are the primary reasons for the loss.  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.  In accordance with a settlement
agreement in Indiana which resolved all Indiana jurisdictional
rate-related issues applicable to the Cook Plant's extended outage
certain restart expenses were deferred in the first quarter of
1999.  A settlement to resolve all rate-related issues in the
Michigan jurisdiction was approved in December 1999 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)
                                              (in millions)   %

   Operating Revenues. . . . . . . . . . . .    $  9.9        3
   Fuel. . . . . . . . . . . . . . . . . . .       6.1       14
   Purchased Power . . . . . . . . . . . . .      22.8       37
   Other Operation . . . . . . . . . . . . .      42.0       46
   Maintenance . . . . . . . . . . . . . . .      24.2       78
   Federal Income Tax. . . . . . . . . . . .     (30.5)     N.M.

   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 to neighboring utility systems and power
marketers by the AEP Power Pool on behalf of the Company offset in
part by the amortization of previously accrued fuel-related
revenues. As a member of the AEP Power Pool, the Company shares in
the revenues and costs of the AEP Power Pool's wholesale sales.
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 more energy due to the expiration
of that affiliate's unit power 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.  The increase in operating revenues
from sales by the AEP Power Pool is due to the significant increase
in AEP Power Pool transactions, which also contributed to the
increase in purchased power.  As a result of an affiliated
company's major industrial customer's decision not to extend its
purchase power agreement, additional power was delivered to the AEP
Power Pool allowing the Power Pool to increase its wholesale sales.
The decrease in revenues caused by the amortization of previously
accrued fuel-related revenues resulted from the amortization in the
current period of revenues accrued through 1999 for the increased
cost of replacement power and increased fossil fuel usage
necessitated by the extended outage of the Cook Nuclear Plant.  The
accrual of revenues was authorized under the terms of approved
settlement agreements for the Indiana and Michigan jurisdictions.
   Fuel expense increased due to a 13.9% rise in generation
reflecting the higher availability of the Company's coal-fired
generating units due to shorter planned maintenance outages.
   The increase in other operation and maintenance expense was
primarily caused by the continuing work to restart the Cook Plant,
combined with the amortization of deferred expenditures under the
terms of the approved settlement agreements in Indiana and
Michigan.
   The decrease in federal income tax expense attributable to
operations was primarily due to a decrease in pre-tax operating
income.
FINANCIAL CONDITION
   Total plant and property additions including capital leases for
the period were $53 million.  During the first three months of 2000
short-term debt outstanding increased by $124 million.  In March
the Company redeemed at maturity $48 million of 6.40% first
mortgage bonds.

<PAGE>
OTHER MATTERS
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.
   In February 2000, the Company was notified by the NRC that the
Confirmatory Action Letter had been closed.  Closing of the
Confirmatory Action Letter is one of the key approvals needed to
restart the nuclear units.  The  Confirmatory Action Letter was
issued in September 1997 requiring the Company to address certain
issues identified in the letter.
   Progress to restart the units continues.  Refueling of Unit 2,
the first unit scheduled to restart, was completed on April 14,
2000.  The NRC's final Unit 2 pre-restart inspection began on May
8, 2000, which coincided with the reactor heat-up of Unit 2 and the
return to operational service of common plant systems.  When
testing and other work required for restart are complete, the
Company will seek concurrence from the NRC to return Unit 2 to
service.  Refueling and maintenance work to restart Unit 1 will be
performed after Unit 2 is returned to service.  Any issues or
difficulties encountered in testing of equipment as part of the
restart process could delay the restart of the units.
   Expenditures to restart the Cook units are estimated to total
approximately $574 million.  Through March 31, 2000, $453 million
has been spent.  In 2000 $80 million of restart costs were recorded
in other operation and maintenance expense, including amortization
of $10 million of restart costs previously deferred in accordance
with settlement agreements in the Indiana and Michigan retail
jurisdictions.
   The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations and cash
flows until the units are restarted.  The amortization of restart
costs deferred under Indiana and Michigan retail jurisdiction
settlement agreements will adversely effect results of operations
and possibly financial condition through 2003 when the amortization
period ends.  Management believes that the Cook units will be
successfully returned to service.  However, if for some unknown
reason the units are not returned to service or their return is
delayed significantly it would have an even greater 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 March 31,
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 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.
   Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
   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.  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 energy.
NOx Reductions
   As discussed in Note 6 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the U.S. Court of Appeals for
the District of Columbia Circuit (Appeals Court) issued a decision
on March 3, 2000 generally upholding Federal EPA's final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states, including the states in which
the Company's generating plants are located. A number of utilities,
including the Company, had filed petitions seeking a review of the
final rule in the 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.  On April 20, 2000,
the AEP System companies and other industry petitioners filed for
rehearing of the March 3, 2000 decision including a rehearing by
the entire Appeals 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
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 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 which represent 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 AEP
Power Pool, has not changed materially since December 31, 1999.
The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at March 31, 2000 is not materially
different than at December 31, 1999.

<PAGE>
<PAGE>
<TABLE>
                      KENTUCKY POWER COMPANY
                       STATEMENTS OF INCOME
                           (UNAUDITED)
<CAPTION>
                                                        Three Months Ended
                                                             March 31,
                                                        2000           1999
                                                           (in thousands)
<S>                                                   <C>            <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . .  $97,204        $90,741

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . .   16,802         19,691
  Purchased Power. . . . . . . . . . . . . . . . . .   33,482         24,427
  Other Operation. . . . . . . . . . . . . . . . . .   10,384         12,351
  Maintenance. . . . . . . . . . . . . . . . . . . .    6,367          4,791
  Depreciation and Amortization. . . . . . . . . . .    7,603          7,190
  Taxes Other Than Federal Income Taxes. . . . . . .    2,834          2,534
  Federal Income Taxes . . . . . . . . . . . . . . .    4,175          4,397

          TOTAL OPERATING EXPENSES . . . . . . . . .   81,647         75,381

OPERATING INCOME . . . . . . . . . . . . . . . . . .   15,557         15,360

NONOPERATING LOSS. . . . . . . . . . . . . . . . . .      (46)          (114)

INCOME BEFORE INTEREST CHARGES . . . . . . . . . . .   15,511         15,246

INTEREST CHARGES . . . . . . . . . . . . . . . . . .    7,459          7,037

NET INCOME . . . . . . . . . . . . . . . . . . . . .  $ 8,052        $ 8,209



                 STATEMENTS OF RETAINED EARNINGS
                           (UNAUDITED)
                                                        Three Months Ended
                                                             March 31,
                                                        2000           1999
                                                           (in thousands)

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

NET INCOME . . . . . . . . . . . . . . . . . . . . .    8,052          8,209

CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . .    7,590          7,443

BALANCE AT END OF PERIOD . . . . . . . . . . . . . .  $67,572        $72,218



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

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                      KENTUCKY POWER COMPANY
                          BALANCE SHEETS
                           (UNAUDITED)
<CAPTION>
                                                   March 31,     December 31,
                                                     2000            1999
                                                        (in thousands)
ASSETS
<S>                                               <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . .    $  269,012      $  268,618
  Transmission . . . . . . . . . . . . . . . .       356,402         355,442
  Distribution . . . . . . . . . . . . . . . .       375,974         372,752
  General. . . . . . . . . . . . . . . . . . .        67,866          67,608
  Construction Work in Progress. . . . . . . .        13,837          14,628
          Total Electric Utility Plant . . . .     1,083,091       1,079,048
  Accumulated Depreciation and Amortization. .       344,027         340,008

          NET ELECTRIC UTILITY PLANT . . . . .       739,064         739,040


OTHER PROPERTY AND INVESTMENTS . . . . . . . .        25,692          20,416


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . .         1,384             674
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . .        20,287          18,952
    Affiliated Companies . . . . . . . . . . .        14,335          15,223
    Miscellaneous. . . . . . . . . . . . . . .         7,979           8,343
    Allowance for Uncollectible Accounts . . .          (615)           (637)
  Fuel . . . . . . . . . . . . . . . . . . . .        11,954          10,441
  Materials and Supplies . . . . . . . . . . .        17,397          18,113
  Accrued Utility Revenues . . . . . . . . . .        10,463          13,737
  Energy Trading Contracts . . . . . . . . . .        64,006          33,919
  Prepayments. . . . . . . . . . . . . . . . .           947           1,450

          TOTAL CURRENT ASSETS . . . . . . . .       148,137         120,215


REGULATORY ASSETS. . . . . . . . . . . . . . .        98,289          96,296


DEFERRED CHARGES . . . . . . . . . . . . . . .         9,136          10,671


            TOTAL. . . . . . . . . . . . . . .    $1,020,318      $  986,638


See Notes to Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
                      KENTUCKY POWER COMPANY
                          BALANCE SHEETS
                           (UNAUDITED)
<CAPTION>
                                                   March 31,     December 31,
                                                     2000            1999
                                                        (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                               <C>              <C>
CAPITALIZATION:
  Common Stock - Par Value $50:
    Authorized -  2,000,000 Shares
    Outstanding - 1,009,000 Shares . . . . . .    $   50,450       $ 50,450
  Paid-in Capital. . . . . . . . . . . . . . .       158,750        158,750
  Retained Earnings. . . . . . . . . . . . . .        67,572         67,110
          Total Common Shareholder's Equity. .       276,772        276,310
  Long-term Debt . . . . . . . . . . . . . . .       260,852        260,782

          TOTAL CAPITALIZATION . . . . . . . .       537,624        537,092

OTHER NONCURRENT LIABILITIES . . . . . . . . .        22,456         23,797

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . .       105,000        105,000
  Short-term Debt. . . . . . . . . . . . . . .        37,600         39,665
  Accounts Payable - General . . . . . . . . .         6,666          9,923
  Accounts Payable - Affiliated Companies. . .        20,666         19,743
  Customer Deposits. . . . . . . . . . . . . .         4,168          4,143
  Taxes Accrued. . . . . . . . . . . . . . . .        10,573          9,860
  Interest Accrued . . . . . . . . . . . . . .         7,199          4,843
  Energy Trading Contracts . . . . . . . . . .        58,347         33,094
  Other. . . . . . . . . . . . . . . . . . . .        10,684         12,020

          TOTAL CURRENT LIABILITIES. . . . . .       260,903        238,291

DEFERRED INCOME TAXES. . . . . . . . . . . . .       166,931        165,007

DEFERRED INVESTMENT TAX CREDITS. . . . . . . .        12,610         12,908

DEFERRED CREDITS . . . . . . . . . . . . . . .        19,794          9,543

CONTINGENCIES (Note 3)

            TOTAL. . . . . . . . . . . . . . .    $1,020,318       $986,638


See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                      KENTUCKY POWER COMPANY
                     STATEMENTS OF CASH FLOWS
                           (UNAUDITED)
<CAPTION>
                                                         Three Months Ended
                                                              March 31,
                                                        2000            1999
                                                           (in thousands)
<S>                                                   <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . .  $ 8,052        $  8,209
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . .    7,605           7,192
    Deferred Federal Income Taxes. . . . . . . . . .    1,961            (254)
    Deferred Investment Tax Credits. . . . . . . . .     (298)           (300)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . .     (105)          4,039
    Fuel, Materials and Supplies . . . . . . . . . .     (797)         (1,893)
    Accrued Utility Revenues . . . . . . . . . . . .    3,274             (13)
    Accounts Payable . . . . . . . . . . . . . . . .   (2,334)         (1,542)
    Taxes Accrued. . . . . . . . . . . . . . . . . .      713           5,131
    Interest Accrued . . . . . . . . . . . . . . . .    2,356           2,554
  Other (net). . . . . . . . . . . . . . . . . . . .   (2,489)          1,519
        Net Cash Flows From Operating Activities . .   17,938          24,642

INVESTING ACTIVITIES - Construction Expenditures . .   (7,573)         (6,483)

FINANCING ACTIVITIES:
  Change in Short-term Debt (net). . . . . . . . . .   (2,065)         (8,400)
  Dividends Paid . . . . . . . . . . . . . . . . . .   (7,590)         (7,443)
        Net Cash Flows Used For
          Financing Activities . . . . . . . . . . .   (9,655)        (15,843)

Net Increase in Cash and Cash Equivalents. . . . . .      710           2,316
Cash and Cash Equivalents at Beginning of Period . .      674           1,935
Cash and Cash Equivalents at End of Period . . . . .  $ 1,384        $  4,251

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was $5,029,000  and
  $4,374,000  in  2000  and  1999,  respectively  and  for  income  taxes  was
  $2,001,000 in 2000.  Noncash acquisitions under capital leases were $374,000
  and $568,000 in 2000 and 1999, respectively.


See Notes to Financial Statements.

<PAGE>
<PAGE>
                      KENTUCKY POWER COMPANY
                  NOTES TO FINANCIAL STATEMENTS
                         MARCH 31, 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. RATE MATTERS

      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.

      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 will make refunds retroactive to September 7,
   1993 to certain customers affected by the July 30, 1999 FERC
   order.  The refunds will be made in two payments.  The first
   payment was made February 2000 pursuant to  a FERC order
   granting AEP's request to make interim refunds.  The remainder
   is to be paid upon approval by the FERC.  In addition, a new
   lower rate of $1.55 kw/month was made effective January 1, 2000,
   for all transmission service customers and a future rate of
   $1.42 kw/month was established to take effect upon the
   consummation of the AEP and Central and South West Corporation
   merger.

3. 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 March 31, 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 Co., 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 for the Southern District of Ohio that alleges
   certain AEP System companies 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.

      Federal EPA also issued Notices of Violation, complaints or
   administrative orders to eight unaffiliated utilities.

      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.  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
   of the 1999 Annual Report, the U.S. Court of Appeals for the
   District of Columbia Circuit (Appeals Court) issued a decision
   on March 3, 2000 generally upholding Federal EPA's final rule
   (the NOx rule) that requires substantial reductions in nitrogen
   oxide (NOx) emissions in 22 eastern states, including Kentucky
   where the Company's generating plant is located. A number of
   utilities, including the Company, had filed petitions seeking
   a review of the final rule in the Appeals Court.  In May 1999,
   the Appeals Court had 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.  On April 20, 2000, the AEP System companies and
   other industry petitioners filed for rehearing of the March 3,
   2000 decision including a rehearing by the entire Appeals 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

            FIRST QUARTER 2000 vs. FIRST QUARTER 1999

      Although revenues rose 7%, net income decreased in the first
quarter primarily as a result of increased interest expense.
Income statement line items which changed significantly were:
                                              Increase(Decrease)
                                              (in millions)  %

     Operating Revenues. . . . . . . . . . .      $ 6.5       7
     Fuel. . . . . . . . . . . . . . . . . .       (2.9)    (15)
     Purchased Power . . . . . . . . . . . .        9.1      37
     Other Operation . . . . . . . . . . . .       (2.0)    (16)
     Maintenance . . . . . . . . . . . . . .        1.6      33
     Depreciation. . . . . . . . . . . . . .        0.4       6
     Net Interest Charges. . . . . . . . . .        0.4       6

     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) wholesale electricity sales.  The
Company as a member of the AEP Power Pool shares in the revenues
and costs of the AEP Power Pool's wholesale electricity marketing
to neighboring utility system and power marketers.  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 sales.  Purchased power also increased
due to an increase in the availability of the Rockport Plant.
Under a non-AEP Power Pool purchase power agreement with an
affiliate, the Company purchases 15% of the available power of the
Rockport Plant.  Rockport Plant generated 16% more kwh in 2000 than
1999.
     Fuel expense decreased due to an outage of the Company's Big
Sandy Plant Unit 2 which began in March 2000.
     The Company as a party to the AEP System's Transmission
Agreement shares the costs associated with the ownership of the AEP
System's 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 applicable
investment in transmission facilities.  The decrease in other
operation expense was primarily due to an increase in transmission
equalization credits as a result of an increase in the Company's
MLR and increased investment in transmission facilities.  Member
load ratio is calculated monthly on the basis of each company's
maximum peak demand in relation to the sum of the maximum peak
demands of all five signatories to the agreement during the
preceding 12 months.
     The Big Sandy Plant began an outage in March 2000 for the
repair and maintenance of Unit 2.  Unit 2 returned to service in
April 2000.
     The increase in transmission plant investment 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 reflecting the Company's short-term
cash demands and short-term debt interest market conditions.

<PAGE>
<PAGE>

</TABLE>
<TABLE>
                  OHIO POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                                Three Months Ended
                                                                     March 31,
                                                                 2000        1999
                                                                  (in thousands)
<S>                                                            <C>         <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . $545,411    $518,221

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . .  215,248     189,163
  Purchased Power. . . . . . . . . . . . . . . . . . . . . . .   35,302      21,273
  Other Operation. . . . . . . . . . . . . . . . . . . . . . .   84,452      85,061
  Maintenance. . . . . . . . . . . . . . . . . . . . . . . . .   28,030      25,490
  Depreciation and Amortization. . . . . . . . . . . . . . . .   38,489      36,785
  Taxes Other Than Federal Income Taxes. . . . . . . . . . . .   43,732      43,853
  Federal Income Taxes . . . . . . . . . . . . . . . . . . . .   35,045      37,640
          TOTAL OPERATING EXPENSES . . . . . . . . . . . . . .  480,298     439,265
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . .   65,113      78,956
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . .    2,900       2,000
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . .   68,013      80,956
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . .   21,797      20,135
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . .   46,216      60,821
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . . .      321         367
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . $ 45,895    $ 60,454



             CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)
                                                                Three Months Ended
                                                                     March 31,
                                                                 2000        1999
                                                                  (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . . $587,424    $587,500

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . .   46,216      60,821

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . . . . . . . . . . . .   37,703      57,703
    Cumulative Preferred Stock . . . . . . . . . . . . . . . .      317         367

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . . $595,620    $590,251


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

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                  OHIO POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                          March 31,     December 31,
                                                            2000            1999
                                                               (in thousands)
ASSETS
<S>                                                      <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .   $2,722,614      $2,713,421
  Transmission . . . . . . . . . . . . . . . . . . . .      860,900         857,420
  Distribution . . . . . . . . . . . . . . . . . . . .    1,010,110         999,679
  General (including mining assets). . . . . . . . . .      715,814         713,882
  Construction Work in Progress. . . . . . . . . . . .      114,260         116,515
          Total Electric Utility Plant . . . . . . . .    5,423,698       5,400,917
  Accumulated Depreciation and Amortization. . . . . .    2,668,873       2,621,711

          NET ELECTRIC UTILITY PLANT . . . . . . . . .    2,754,825       2,779,206



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .      277,790         253,668



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .      226,877         157,138
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .      235,875         246,310
    Affiliated Companies . . . . . . . . . . . . . . .      158,457          89,215
    Miscellaneous. . . . . . . . . . . . . . . . . . .       27,395          22,055
    Allowance for Uncollectible Accounts . . . . . . .       (2,100)         (2,223)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .      131,478         146,317
  Materials and Supplies . . . . . . . . . . . . . . .       97,092          95,967
  Accrued Utility Revenues . . . . . . . . . . . . . .       33,056          45,575
  Energy Trading Contracts . . . . . . . . . . . . . .      234,374         134,567
  Prepayments and Other. . . . . . . . . . . . . . . .       43,413          38,472

          TOTAL CURRENT ASSETS . . . . . . . . . . . .    1,185,917         973,393


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .      584,216         577,090


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .       80,289          93,852


            TOTAL. . . . . . . . . . . . . . . . . . .   $4,883,037      $4,677,209


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                  OHIO POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                         March 31,      December 31,
                                                           2000             1999
                                                              (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                     <C>              <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  40,000,000 Shares
    Outstanding - 27,952,473 Shares. . . . . . . . . .  $  321,201       $  321,201
  Paid-in Capital. . . . . . . . . . . . . . . . . . .     462,402          462,376
  Retained Earnings. . . . . . . . . . . . . . . . . .     595,620          587,424
          Total Common Shareholder's Equity. . . . . .   1,379,223        1,371,001
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .      16,865           16,937
    Subject to Mandatory Redemption. . . . . . . . . .       8,850            8,850
  Long-term Debt . . . . . . . . . . . . . . . . . . .   1,130,492        1,139,834

          TOTAL CAPITALIZATION . . . . . . . . . . . .   2,535,430        2,536,622

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .     431,672          414,837

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .      11,881           11,677
  Short-term Debt. . . . . . . . . . . . . . . . . . .     241,424          194,918
  Accounts Payable - General . . . . . . . . . . . . .     183,173          180,383
  Accounts Payable - Affiliated Companies. . . . . . .      81,424           64,599
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .     160,788          179,112
  Interest Accrued . . . . . . . . . . . . . . . . . .      23,412           16,863
  Obligations Under Capital Leases . . . . . . . . . .      34,166           34,284
  Energy Trading Contracts . . . . . . . . . . . . . .     213,651          131,844
  Other. . . . . . . . . . . . . . . . . . . . . . . .     110,299           96,445

          TOTAL CURRENT LIABILITIES. . . . . . . . . .   1,060,218          910,125

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .     666,369          676,460

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .      35,021           35,838

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .     154,327          103,327

CONTINGENCIES (Note 4)

            TOTAL. . . . . . . . . . . . . . . . . . .  $4,883,037       $4,677,209


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                  OHIO POWER COMPANY AND SUBSIDIARIES
                 CONSOLIDATED STATEMENTS OF CASH FLOWS
                              (UNAUDITED)
<CAPTION>
                                                               Three Months Ended
                                                                    March 31,
                                                               2000          1999
                                                                 (in thousands)
<S>                                                         <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . .  $  46,216     $  60,821
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . .     60,294        45,129
    Deferred Federal Income Taxes. . . . . . . . . . . . .    (14,957)       (3,601)
    Deferred Fuel Costs (net). . . . . . . . . . . . . . .     (3,961)       (7,227)
    Amortization of Deferred Property Taxes. . . . . . . .     19,666        19,426
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . .    (64,270)     (107,053)
    Fuel, Materials and Supplies . . . . . . . . . . . . .     13,714       (20,409)
    Accrued Utility Revenues . . . . . . . . . . . . . . .     12,519         4,082
    Prepayments and Other. . . . . . . . . . . . . . . . .     (4,941)      (13,013)
    Accounts Payable . . . . . . . . . . . . . . . . . . .     19,615         6,374
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . .    (18,324)        3,019
    Interest Accrued . . . . . . . . . . . . . . . . . . .      6,549         9,025
  Operating Reserves . . . . . . . . . . . . . . . . . . .     22,694        17,519
  Other (net). . . . . . . . . . . . . . . . . . . . . . .     16,082        24,364
        Net Cash Flows From Operating Activities . . . . .    110,896        38,456

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . .    (40,684)      (41,888)
  Proceeds from Sale of Property and Other . . . . . . . .       -              629
        Net Cash Flows Used For Investing Activities . . .    (40,684)      (41,259)

FINANCING ACTIVITIES:
  Change in Short-term Debt (net). . . . . . . . . . . . .     46,506        96,695
  Retirement of Cumulative Preferred Stock . . . . . . . .        (46)          (10)
  Retirement of Long-term Debt . . . . . . . . . . . . . .     (8,883)      (10,679)
  Dividends Paid on Common Stock . . . . . . . . . . . . .    (37,733)      (57,703)
  Dividends Paid on Cumulative Preferred Stock . . . . . .       (317)         (367)
        Net Cash Flows From (Used For)
          Financing Activities . . . . . . . . . . . . . .       (473)       27,936

Net Increase in Cash and Cash Equivalents. . . . . . . . .     69,739        25,133
Cash and Cash Equivalents at Beginning of Period . . . . .    157,138        89,652
Cash and Cash Equivalents at End of Period . . . . . . . .  $ 226,877     $ 114,785

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $15,043,000 and $10,562,000
  and for income taxes was $20,652,000 and $2,219,000 in 2000 and 1999,
  respectively.  Noncash  acquisitions  under  capital  leases  were $2,791,000 and
  $5,634,000 in 2000 and 1999, respectively.


See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
                  OHIO POWER COMPANY AND SUBSIDIARIES
              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                            MARCH 31, 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.   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.

          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 will make
     refunds retroactive to September 7, 1993 to certain customers
     affected by the July 30, 1999 FERC order.  The refunds will be made
     in two payments.  The first payment was made February 2000 pursuant
     to  a FERC order granting AEP's request to make interim refunds.
     The remainder is to be paid upon approval by the FERC.  In addition,
     a new lower rate of $1.55 kw/month was made effective January 1,
     2000, for all transmission service customers and a future rate of
     $1.42 kw/month was established to take effect upon the consummation
     of the AEP and Central and South West Corporation merger.

3.   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 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 would not 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.  The
     key provisions of the stipulation agreement are:

              Recovery of regulatory assets over seven years.
              No shopping incentive for the Company's customers.
              The Company is to absorb 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
              for certain transmission charges imposed by PJM and/or
              Midwest ISO on generation originating in the Midwest
              ISO or PJM.
              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 will be litigated.  Hearings to address the gross
              receipts tax issue are scheduled for May 31, 2000.

          The stipulation agreement is subject to approval by the PUCO.
     Hearings on the stipulation are scheduled for June 7, 2000.

          Management has concluded that as of March 31, 2000 the
     requirements to apply Statement of Financial Accounting Standard
     (SFAS) No. 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 the transition plan
     should 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 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 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 March
     31, 2000 applicable to the Ohio retail jurisdictional generating
     business is $422 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 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.

          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 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.

4.   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 March 31,
     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 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.

<PAGE>
          Federal EPA also issued Notices of Violation, complaints or
     administrative orders to eight unaffiliated utilities.

          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.  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, the U.S. Court of Appeals for
     the District of Columbia Circuit (Appeals Court) issued a decision
     on March 3, 2000 generally upholding Federal EPA's final rule (the
     NOx rule) that requires substantial reductions in nitrogen oxide
     (NOx) emissions in 22 eastern states, including the states in which
     the Company's generating plants are located. A number of utilities,
     including the Company, had filed petitions seeking a review of the
     final rule in the 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.  On April 20, 2000,
     the AEP System companies and other industry petitioners filed for
     rehearing of the March 3, 2000 decision including a rehearing by the
     entire Appeals Court.

          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

               FIRST QUARTER 2000 vs. FIRST QUARTER 1999

RESULTS OF OPERATIONS
     Net income decreased $15 million or 24% due mainly to an increase
in fuel and purchased power expense.
     Income statement line items which changed significantly were:
                                              Increase (Decrease)
                                              (in millions)    %

     Operating Revenues . . . . . . . . . .      $27.2         5
     Fuel . . . . . . . . . . . . . . . . .       26.1        14
     Purchased Power. . . . . . . . . . . .       14.0        66
     Maintenance. . . . . . . . . . . . . .        2.5        10
     Federal Income Taxes . . . . . . . . .       (2.5)       (7)

     The increase in operating revenues resulted from increased sales to
the American Electric Power System Power Pool (AEP Power Pool) and the
Company's share of revenues from increased sales to neighboring utility
systems and power marketers by the AEP Power Pool.  As a member of the
AEP Power Pool, the Company shares in the revenues and costs of the AEP
Power Pool's wholesale sales.  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
a major industrial customer's decision not to continue its purchased
power agreement with the Company, additional power was delivered to the
AEP Power Pool, accounting for the increase in sales to the AEP Power
Pool.
     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.
     The significant increase in purchased power expense resulted from
the shared costs of AEP Power Pool purchases and power purchased from
non-associated companies for sale in the wholesale market.
     Additional boiler repairs accounted for the increase in maintenance
expense.

<PAGE>
     The decrease in federal income tax expense attributable to
operations was primarily due to a decrease in pre-tax operating income
offset in part by changes in certain book/tax differences accounted for
on a flow-through basis.
FINANCIAL CONDITION
     Total plant and property additions including capital leases for the
current period were $43 million.  Short-term debt increased by $47
million from the beginning of 2000.
OTHER MATTERS
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 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 would not 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.  The key provisions of the
stipulation agreement are:
          Recovery of regulatory assets over seven years.
          No shopping incentive for the Company's customers.
          The Company is to absorb 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 for certain
          transmission charges imposed by PJM and/or Midwest ISO
          on generation originating in the Midwest ISO or PJM.
          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
          will be litigated.  Hearings to address the gross receipts tax
          issue are scheduled for May 31, 2000.
     The stipulation agreement is subject to approval by the PUCO.
Hearings on the stipulation are scheduled for June 7, 2000.
     Management has concluded that as of March 31, 2000 the requirements
to apply Statement of Financial Accounting Standard (SFAS) No. 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 the transition plan should 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 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 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 March 31,
2000 applicable to the Ohio retail jurisdictional generating business is
$422 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 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.
     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 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.
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 March 31, 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 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.
     Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
     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.  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, the U.S. Court of Appeals for the
District of Columbia Circuit (Appeals Court) issued a decision on March
3, 2000 generally upholding Federal EPA's final rule (the NOx rule) that
requires substantial reductions in nitrogen oxide (NOx) emissions in 22
eastern states, including the states in which the Company's generating
plants are located. A number of utilities, including the Company, had
filed petitions seeking a review of the final rule in the 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.  On
April 20, 2000, the AEP System companies and other industry petitioners
filed for rehearing of the March 3, 2000 decision including a rehearing
by the entire Appeals Court.
     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 which represent the risk of loss that may impact the Company
due to adverse changes in commodity market prices and interest rates
from changes in electricity commodity 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, has not
changed materially since December 31, 1999.  The exposure to changes in
interest rates from the Company's short-term and long-term borrowings at
March 31, 2000 is not materially different than at December 31, 1999.

<PAGE>
<PAGE>
PART II.  OTHER INFORMATION



Item 5.  Other Information.

American Electric Power Company, Inc. ("AEP"), AEP Generating Company
("AEGCo"), Appalachian Power Company ("APCo"), Columbus Southern Power
Company ("CSPCo"), Indiana Michigan Power Company ("I&M"), Kentucky
Power Company ("KEPCo") and Ohio Power Company ("OPCo")

     Reference is made to page 36 of the Annual Report on Form 10-K for
the year ended December 31, 1999 ("1999 10-K") for a discussion of the
review by the United States Environmental Protection Agency ("Federal
EPA") of low volume coal combustion wastes.  On April 25, 2000, Federal
EPA issued a regulatory determination that low volume wastes from coal
combustion that are mixed with and co-treated or co-disposed with high
volume coal combustion wastes do not warrant regulation under RCRA
Subtitle C as hazardous waste.  Instead, Federal EPA indicated that it
would develop national Subtitle D solid waste standards applicable to
disposal of all coal combustion wastes in surface impoundments and
landfills.  According to Federal EPA's regulatory determination, Federal
EPA intends to apply these national regulations to both high volume coal
combustion wastes co-managed with low volume wastes and high volume coal
combustion wastes previously addressed in the 1993 regulatory
determination that are separately disposed of.  Federal EPA also
determined that additional regulation would be necessary for use of coal
combustion by-products to fill surface or underground mines.

     If the RCRA Subtitle D national standards that are to be developed
by Federal EPA for coal combustion wastes would be more stringent than
currently applicable state regulations, AEP System facilities could
incur additional waste management expenses.  The significance of these
cost increases, or the timing of Federal EPA's finalization of these
national standards, cannot be determined at this time.

AEP and OPCo

     Reference is made to page 43 of the 1999 10-K for a discussion of
litigation with Ormet Corporation involving the ownership of sulfur
dioxide allowances.  On March 27, 2000, the U.S. Court of Appeals for
the Fourth Circuit issued a decision affirming the judgment of the
District Court that granted the motion of OPCo and AEP Service
Corporation for summary judgment.






<PAGE>
<PAGE>
Item 6.  Exhibits and Reports on Form 8-K.

(a) Exhibits:

          APCo, CSPCo, I&M, KEPCo and OPCo

              Exhibit 12 - Statement re: Computation of Ratios.

          AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo

              Exhibit 27 - Financial Data Schedule.


     (b)  Reports on Form 8-K:

          AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo

              No reports on Form 8-K were filed during the quarter ended
March 31, 2000.



<PAGE>
<PAGE>
                               Signature




     Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf
by the undersigned thereunto duly authorized.  The signature for each
undersigned company shall be deemed to relate only to matters having
reference to such company and any subsidiaries thereof.

                 AMERICAN ELECTRIC POWER COMPANY, INC.



     By: /s/  Armando A. Pena       By: /s/  Leonard V. Assante
             Armando A. Pena              Leonard V. Assante
             Treasurer                    Controller and
                                          Chief Accounting Officer
          (Duly Authorized Officer)    (Chief Accounting Officer)



                        AEP GENERATING COMPANY
                       APPALACHIAN POWER COMPANY
                    COLUMBUS SOUTHERN POWER COMPANY
                    INDIANA MICHIGAN POWER COMPANY
                        KENTUCKY POWER COMPANY
                          OHIO POWER COMPANY



     By: /s/  Armando A. Pena       By: /s/  Leonard V. Assante
             Armando A. Pena              Leonard V. Assante
             Vice President, Treasurer,   Controller and
             and Chief Financial Officer  Chief Accounting Officer
          (Duly Authorized Officer)     (Chief Accounting Officer)


Date: May 11, 2000








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