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

<PAGE>
<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, 1999

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

            For The Transition Period from          to         
<CAPTION>
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., Caton, 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, 1999 was 192,726,681.
/TABLE
<PAGE>
<PAGE>
<TABLE>
    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                               FORM 10-Q

                 For The Quarter Ended March 31, 1999
<CAPTION>
                                 INDEX

                                                                          Page
Part I.  FINANCIAL INFORMATION
           <S>                                                            <C> 
           American Electric Power Company, Inc. and Subsidiary Companies:
             Consolidated Statements of Income and 
               Statements of Retained Earnings. . . . . . . . . . . . . . A-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2- A-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4
             Notes to Consolidated Financial Statements . . . . . . . . .  A-5- A-13 
           Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . A-14-A-28

           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-8
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . C-9 - C-16

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

           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-7
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . E-8 - 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-6
             Management's Narrative Analysis of Results of Operations . . F-7 - F-8


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

                                                FORM 10-Q

                                          For The Quarter Ended March 31, 1999

                                                  INDEX

                                                                        Page
           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-6
             Management's Discussion and Analysis of Results of 
               Operations and Financial Condition . . . . . . . . . . . G-7 - G-12


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>
<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,        
                                                              1999           1998
<S>                                                          <C>            <C>
REVENUES:
  Domestic Regulated Electric Utilities. . . . . . . . . .   $1,550         $1,509
  Worldwide Non-regulated Electric and Gas Operations. . .      144             12

          TOTAL REVENUES . . . . . . . . . . . . . . . . .    1,694          1,521

EXPENSES:
  Fuel and Purchased Power . . . . . . . . . . . . . . . .      491            485
  Maintenance and Other Operation. . . . . . . . . . . . .      427            411
  Depreciation and Amortization. . . . . . . . . . . . . .      148            144
  Taxes Other Than Income Taxes. . . . . . . . . . . . . .      124            122
  Worldwide Non-regulated Electric and Gas Operations. . .      123             15

         TOTAL EXPENSES. . . . . . . . . . . . . . . . . .    1,313          1,177

OPERATING INCOME . . . . . . . . . . . . . . . . . . . . .      381            344
OTHER LOSS, net. . . . . . . . . . . . . . . . . . . . . .       (5)            (4)
INCOME BEFORE INTEREST, PREFERRED DIVIDENDS 
  AND INCOME TAXES . . . . . . . . . . . . . . . . . . . .      376            340
INTEREST AND PREFERRED DIVIDENDS . . . . . . . . . . . . .      132            106
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . .      244            234
INCOME TAXES . . . . . . . . . . . . . . . . . . . . . . .       93             83
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .   $  151         $  151
AVERAGE NUMBER OF SHARES OUTSTANDING . . . . . . . . . . .      192            190
EARNINGS PER SHARE . . . . . . . . . . . . . . . . . . . .    $0.79          $0.79
CASH DIVIDENDS PAID PER SHARE. . . . . . . . . . . . . . .    $0.60          $0.60

                                                                  

             CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)
                                                              Three Months Ended
                                                                   March 31,        
                                                              1999           1998
                                                                 (in millions)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . .  $1,684          $1,605

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

DEDUCTIONS:
  Cash Dividends Declared. . . . . . . . . . . . . . . . .     115             114

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . .  $1,720          $1,642

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,
                                                               1999           1998   

                                                                 (in millions)
ASSETS
<S>                                                          <C>            <C>
CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .       $   280        $   173
  Accounts Receivable (net). . . . . . . . . . . . . .           854            879
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .           262            216
  Materials and Supplies . . . . . . . . . . . . . . .           282            280
  Accrued Utility Revenues . . . . . . . . . . . . . .           183            214
  Energy Marketing and Trading Contracts . . . . . . .           603            372
  Prepayments. . . . . . . . . . . . . . . . . . . . .           126             84

          TOTAL CURRENT ASSETS . . . . . . . . . . . .         2,590          2,218

PLANT, PROPERTY AND EQUIPMENT:
  Electric:
      Production . . . . . . . . . . . . . . . . . . .         9,805          9,615
      Transmission . . . . . . . . . . . . . . . . . .         3,592          3,692
      Distribution . . . . . . . . . . . . . . . . . .         5,395          5,125
  Other (including gas and coal mining assets 
   and nuclear fuel) . . . . . . . . . . . . . . . . .         2,104          2,118
  Construction Work in Progress. . . . . . . . . . . .           696            801
          Total Plant, Property and Equipment. . . . .        21,592         21,351
  Accumulated Depreciation and Amortization. . . . . .         8,777          8,549

          NET PLANT, PROPERTY AND EQUIPMENT. . . . . .        12,815         12,802


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         1,908          1,847



OTHER ASSETS . . . . . . . . . . . . . . . . . . . . .         2,817          2,616



            TOTAL. . . . . . . . . . . . . . . . . . .       $20,130        $19,483

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,
                                                               1999           1998   

                                                                  (in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S>                                                          <C>            <C>
CURRENT LIABILITIES:
  Accounts Payable . . . . . . . . . . . . . . . . . .       $   741        $   618
  Short-term Debt. . . . . . . . . . . . . . . . . . .           626            617
  Long-term Debt Due Within One Year . . . . . . . . .           490            206
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .           387            382
  Interest Accrued . . . . . . . . . . . . . . . . . .           117             75
  Obligations Under Capital Leases . . . . . . . . . .            83             82
  Energy Marketing and Trading Contracts . . . . . . .           585            360
  Other. . . . . . . . . . . . . . . . . . . . . . . .           540            461

          TOTAL CURRENT LIABILITIES. . . . . . . . . .         3,569          2,801

LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . .         6,542          6,800

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .         2,616          2,601

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .           345            351

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .           220            222

DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . .           336            263

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .         1,413          1,429

CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . .           174            174

CONTINGENCIES (Note 8)

COMMON SHAREHOLDERS' EQUITY
  Common Stock-Par Value $6.50:
                                 1999         1998
    Shares Authorized . . . .600,000,000   600,000,000
    Shares Issued . . . . . .201,561,414   200,816,469
    (8,999,992 shares were held in treasury) . . . . .       $ 1,310       $ 1,305
  Paid-in Capital. . . . . . . . . . . . . . . . . . .         1,885         1,853
  Retained Earnings. . . . . . . . . . . . . . . . . .         1,720         1,684

          TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . .         4,915         4,842

            TOTAL. . . . . . . . . . . . . . . . . . .       $20,130       $19,483

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,       
                                                                 1999         1998
<S>                                                              <C>          <C>
                                                                   (in millions)
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .     $ 151        $ 151
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .       172          153
    Deferred Federal Income Taxes. . . . . . . . . . . . . .        30            8
    Deferred Investment Tax Credits. . . . . . . . . . . . .        (6)          (6)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .        25          (47)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .       (48)           7
    Accrued Utility Revenues . . . . . . . . . . . . . . . .        31           26
    Prepayments. . . . . . . . . . . . . . . . . . . . . . .       (42)         (11)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .       123          (11)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .         5           35
    Interest Accrued . . . . . . . . . . . . . . . . . . . .        42           34
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .        37           37
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .      (117)         (37)
        Net Cash Flows From Operating Activities . . . . . .       403          339

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .      (212)        (153)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .        (5)          (8)
        Net Cash Flows Used For Investing Activities . . . .      (217)        (161)

FINANCING ACTIVITIES:
  Issuance of Common Stock . . . . . . . . . . . . . . . . .        31           19
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .         7          184
  Change in Short-term Debt (net). . . . . . . . . . . . . .         9           85
  Retirement of Long-term Debt . . . . . . . . . . . . . . .       (11)        (310)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .      (115)        (114)
        Net Cash Flows Used For Financing Activities . . . .       (79)        (136)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .       107           42
Cash and Cash Equivalents at Beginning of Period . . . . . .       173           91
Cash and Cash Equivalents at End of Period . . . . . . . . .     $ 280        $ 133

Supplemental Disclosure:
  Cash paid for interest net of  capitalized amounts was  $84 million and $66 million 
  and for income taxes was $3 million and $2 million  in 1999 and 1998, respectively.
  Noncash acquisitions  under capital leases were $18 million and $47 million in 1999
  and 1998, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
  AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                          MARCH 31, 1999                        
                           (UNAUDITED)

1. GENERAL

        The accompanying unaudited consolidated financial state-ments should be
   read in conjunction with the 1998 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 AND RELATED ACTIVITIES

        In April 1999 subsidiaries called $243 million of
   outstanding first mortgage bonds for early redemption in May
   1999.  Consequently the bonds were reclassified as a current
   liability on the Consolidated Balance Sheets.

3. NEW ACCOUNTING STANDARD


        In the first quarter of 1999 the Company adopted the
   Financial Accounting Standards Board's Emerging Issues Task
   Force Consensus (EITF) 98-10, "Accounting for Contracts
   Involved in Energy Trading and Risk Management Activities". The
   EITF requires that all energy trading contracts be marked-to-market.  
   The effect on the Consolidated Statements of Income
   from marking open trading contracts to market is deferred as
   regulatory assets or liabilities for the portion of open
   trading transactions that are included in cost of service on
   a settlement basis for ratemaking purposes in jurisdictions
   other than the Virginia retail jurisdiction.  As a result of
   a prohibition against establishing additional regulatory assets
   contained in a Virginia settlement agreement, the Virginia
   retail jurisdictional share of the mark-to-market adjustment
   is included in net income.  The adoption of the EITF did not
   have a material effect on results of operations, cash flows or
   financial condition.

4. 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 <PAGE>
   AEP's consolidated
   financial statements represent summarized
   consolidated financial information of Yorkshire:

                                          Three Months Ended
                                               March 31,     
                                          1999          1998
                                             (in millions)
   Income Statement Data:
     Operating Revenues                 $652.0        $663.2
     Operating Income                    113.5          89.7
     Net Income                           34.6           6.9

5. BUSINESS SEGMENTS

        As of December 31, 1998, the Company adopted Statement of
   Financial Accounting Standards (SFAS) 131, "Disclosure about
   Segments of an Enterprise and Related Information."  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 electric power
   wholesale marketing and trading activities that are conducted
   as part of regulated operations and subject to regulatory
   ratemaking oversight.  The World Wide Energy Investments
   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 1999
   and 1998 is in the following table:
<TABLE>
<CAPTION> 
                                Regulated
                                 Domestic    World
                                 Electric    Wide Energy              Reconciling    AEP
                                 Utilities   Investments    Other     Adjustments    Consolidated
         
                                                (in millions)
 March 31, 1999               
<S>                         <C>           <C>            <C>          <C>          <C>
Revenues from
     external customers     $ 1,550       $  165         $ 27         $(48)        $ 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
 March 31, 1998
   Revenues from
     external customers       1,509           11            1           -           1,521
   Revenues from
     transactions with other
     operating segments        -             -             -            -            -
   Segment net income (loss)    156           (2)          (3)          -             151
   Total assets              16,340          406           52           -          16,798<PAGE>
6. MERGER
</TABLE>
        As discussed in Note 5 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the Company and
   Central and South West Corporation (CSW) announced plans to
   merge in December 1997.  In 1998 the appropriate shareholder
   proposals for the consummation of the merger were approved. 
   Approval of the merger has been requested from the Federal
   Energy Regulatory Commission (FERC), the Securities and
   Exchange Commission (SEC), the Nuclear Regulatory Commission
   (NRC) and all of CSW's state regulatory commissions: Arkansas,
   Louisiana, Oklahoma and Texas.  In the near future, AEP and CSW
   plan to make the final two filings associated with approval of
   the merger with the Federal Communications Commission and the
   Department of Justice.  The NRC and the Arkansas Public Service
   Commission approved the merger in 1998.  In 1998 the FERC
   issued an order which confirmed that a 250 megawatt 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.

        In 1998 the FERC issued an order establishing hearing
   procedures for the merger and scheduled the hearings to begin
   on June 1, 1999.  Subsequently, the FERC postponed the hearings
   until June 29, 1999.  The 1998 FERC order indicated that the
   review of the proposed merger will address the issues of
   competition, market power and customer protection and
   instructed the companies to refile an updated market power
   study.  On January 13, 1999, AEP and CSW filed an updated
   market power study with the FERC.

        On May 11, 1999, the Oklahoma Corporation Commission (OCC)
   approved the proposed merger between the Company and CSW.  The
   approval follows an administrative law judge's oral decision
   on a partial settlement between certain principal parties to
   the Oklahoma merger proceeding which recommended that the OCC
   approve the merger.  The partial settlement provides for
   sharing of net merger savings with Oklahoma customers; no
   increase of Oklahoma base rates prior to January 1, 2003;
   filing by December 31, 2001 with the FERC an application to
   join a regional transmission organization; and implementing
   additional quality of service standards for Oklahoma retail
   customers.  Oklahoma's share (approximately $50 million) of net
   merger savings over the first five years after the merger is
   consummated will be split between Oklahoma customers and AEP
   shareholders, with customers receiving approximately 55% of the
   net savings.  The partial settlement agreement includes a
   recommendation by the OCC staff that the OCC file with FERC
   indicating that it does not oppose the merger, but reserves the
   right to ensure that there are no adverse impacts on the
   Oklahoma transmission system.

<PAGE>
        On May 4, 1999, AEP and CSW announced that a stipulated
   settlement had been reached in Texas.  The agreement builds
   upon an earlier settlement agreement signed by AEP, CSW and
   certain parties to the Texas merger proceeding.  In addition
   to the parties that were signatories to the earlier agreement,
   the staff of the Public Utility Commission of Texas is a
   signatory to the new settlement as well as other key parties
   to the merger proceeding.  The stipulated settlement would
   result in rate reductions totaling $221 million over a six-year
   period for Texas customers after the merger is completed.  The
   $221 million rate reduction represents $84.4 million of net
   merger savings and $136.6 million to resolve existing issues
   associated with CSW operating subsidiaries' rate and fuel
   reconciliation proceedings in Texas.  Under the terms of the
   settlement agreement, base rates would not be increased before
   January 1, 2003 or three years after the merger, whichever is
   later.  The settlement also calls for the divestiture of a
   total of 1,604 megawatts of existing and proposed generating
   capacity within Texas.  If it is determined that the
   divestiture can proceed immediately after the merger closes
   without jeopardizing pooling-of-interests accounting treatment
   for the merger, sale of the plants would begin no later than
   90 days after the merger closes.  Absent that determination,
   the divestiture would occur approximately two years after the
   merger closes to satisfy the requirements to use pooling-of-interests 
   accounting treatment.  Other provisions in the
   settlement agreement provide for, among other things,
   accelerated stranded cost recovery, quality-of-service
   standards, continuation of programs for disadvantaged customers
   and transfer of control of bulk transmission facilities to a
   regional transmission organization.

        The Indiana Utility Regulatory Commission (IURC) approved
   a settlement agreement related to the merger on April 26, 1999. 
   The settlement agreement resulted from an investigation of the
   proposed merger between AEP and CSW initiated by the IURC.  The
   terms of the settlement agreement provide for, among other
   things, a sharing of net merger savings through reductions in
   customers' bills of approximately $67 million over eight years
   after the merger is completed; a one year extension through
   January 1, 2005 of a freeze in base rates; additional annual
   deposits of $5.5 million to the nuclear decommissioning trust
   fund for the Indiana jurisdiction for the years 2001 through
   2003; quality-of-service standards; and participation in a
   regional transmission organization.  As part of the settlement
   agreement, the IURC agreed not to oppose the merger in FERC or
   SEC  proceedings.

        AEP and CSW reached a settlement with the local unions of
   the International Brotherhood of Electrical Workers (IBEW)
   representing employees of AEP and CSW.  Under the terms of the
   settlement, AEP and CSW will not terminate any current IBEW
   employee as a result of the merger and existing labor
   agreements will be recognized by the merged company.  As part
   of the settlement, the IBEW local unions will withdraw their
   opposition to completing the merger.

        On April 15, 1999, in compliance with a request from the
   staff of the Kentucky Public Service Commission (KPSC) AEP
   filed an application seeking KPSC approval for the indirect
   change in control of Kentucky Power Company that will occur as
   a result of the proposed merger.  AEP does not believe that the
   KPSC has the jurisdictional authority to approve the merger. 
   Under the governing statute the KPSC must act on the
   application within 60 days.  Therefore the KPSC proceeding is
   not expected to impact the timing of the merger.

        In April 1999 AEP and CSW announced that settlements were
   reached with certain wholesale customers that address issues
   related to the proposed merger.  Under the terms of the
   settlements the wholesale customers agreed not to oppose the
   merger in FERC or SEC proceedings.

        The proposed merger of CSW into AEP would result in common
   ownership of two United Kingdom (UK) regional electricity
   companies (RECs), Yorkshire and Seeboard, plc.  AEP has a 50%
   ownership interest in Yorkshire and CSW has a 100% interest in
   Seeboard.  Although the merger of CSW into AEP is not subject
   to approval by UK regulatory authorities, the common ownership
   of two UK RECs could be referred by the UK Secretary of State
   for Trade and Industry to the UK Competition Commission
   (formerly Monopolies and Mergers Commission) for investigation.

        The merger is conditioned upon, among other things, the
   approval of the above state and federal regulatory agencies. 
   The transaction must satisfy many conditions, a number of which
   may not be waived by the parties, including the condition that
   the merger must be accounted for as a pooling of interests. 
   The merger agreement will terminate on December 31, 1999 unless
   extended by either party as provided in the merger agreement. 
   Although consummation of the merger is expected to occur in the
   fourth quarter of 1999, the Company is unable to predict the
   outcome or the timing of the required regulatory proceedings

7. VIRGINIA RESTRUCTURING

        In March 1999, a new law was enacted in Virginia to
   restructure the electric utility industry.  Under the
   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.  Provisions allowing for an
   acceleration or limited delay in this schedule are also
   contained in the law.  Except as provided in the law, the
   generation of electricity will not be subject to rate
   regulation after January 1, 2002.  Additionally, each Virginia
   electric utility is required by 2001 to join or establish a
   regional transmission entity which will manage and control
   transmission assets.
<PAGE>
        The Virginia restructuring law also provides an opportunity
   for recovery of just and reasonable net stranded costs. 
   Stranded costs are those costs above market including
   generation related net regulatory assets and impaired tangible
   assets that potentially would not be recoverable in a
   competitive market.  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. The
   capped rates may be terminated after January 1, 2004, and prior
   to July 1, 2007, based upon the Virginia SCC determining that
   an effective competitive market exists.  The wires charge will
   be equal to the difference between the generation component of
   the capped rates and the market price for generation service
   and will be imposed upon departing customers through the
   expiration of the rate cap period.

        Management has reviewed all the evidence currently
   available and concluded that as of March 31, 1999 the
   requirements to apply SFAS 71, "Accounting for the Effects of
   Certain Types of Regulation," continue to be met for the
   Virginia retail jurisdiction.  The Company's Virginia rates for
   generation will continue to be cost-based regulated until the
   establishment of capped rates as provided in the law.  When
   capped rates are established in Virginia, the application of
   SFAS 71 would be discontinued for the Virginia retail
   jurisdiction portion of the generating business.  At that time
   generation-related regulatory assets applicable to the Virginia
   jurisdiction will be written off to the extent that they cannot
   be recovered under the provisions of the restructuring law and
   generating assets for the Virginia retail jurisdiction will be
   evaluated for impairment.  An impairment loss would be recorded
   to the extent that such assets cannot be recovered through the
   transition recovery mechanisms provided by the law.  The amount
   of regulatory assets applicable to the Virginia generating
   business at March 31, 1999 is estimated to be $61 million
   before related tax effects and any possible offsetting
   regulatory liabilities.  Regulatory liabilities applicable to
   the Virginia generation business at March 31, 1999 are
   estimated to be $38 million of which $25 million represents
   deferred investment tax credits (ITC).  The Company is
   evaluating the tax normalization rules regarding the timing of
   the reversal of deferred ITC in connection with the Virginia
   restructuring law and the ability to record a reversal of
   deferred ITC in the same accounting periods when any possible
   losses from unrecovered regulatory assets are recorded.  Should
   it not be possible under the Virginia law to recover all or a
   portion of the generation net regulatory  assets, it could have
   a material adverse impact on results of operations; however,
   the amount of any impairment loss for Virginia retail
   jurisdictional generating assets and any loss from a possible
   inability to recover generation net regulatory assets cannot
   be estimated until such time as capped rates are determined
   under the law.

8. CONTINGENCIES

   Litigation

        As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the
   deductibility of certain interest deductions related to AEP's
   corporate owned life insurance (COLI) program for taxable years
   1991-1996 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 COLI
   interest deductions through March 31, 1999 would reduce
   earnings by approximately $316 million (including interest). 
   The Company has made no provision for any possible earnings
   impact from this matter. 

        In 1998 the Company made payments of taxes and interest
   attributable to COLI interest deductions for taxable years
   1991-1997 to avoid the potential assessment by the IRS of any
   additional above market rate interest on the contested amount.
   These payments to the IRS are included on the Consolidated
   Balance Sheets in other assets pending the resolution of this
   matter.  The Company will seek refund, either administratively
   or through litigation, of all amounts paid plus interest.

        In order to resolve this issue, the Company filed suit
   against the United States (US) in the US District Court for the
   Southern District of Ohio in March 1998.  Management believes
   that it has a meritorious position and will vigorously pursue
   this lawsuit.  In the event the resolution of this matter is
   unfavorable, it will have a material adverse impact on results
   of operations.

   Cook Plant Shutdown

        As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, both units of
   the Cook Plant were shut down in September 1997 due to
   questions regarding the operability of certain safety systems
   which arose during a NRC architect engineer design inspection. 
   The NRC issued a Confirmatory Action Letter in September 1997
   requiring the Company to address certain issues identified in
   the letter.  During 1998 the NRC notified the Company that it
   had convened a Restart Panel for Cook Plant and provided a list
   of required restart activities.  In order to identify and
   resolve all issues, including those in the letter, necessary
   to restart the Cook units, the Company is working with the NRC
   and will be meeting with the Panel on a regular basis, until
   the units are returned to service.

        In January 1999 the Company announced that additional
   engineering reviews will be conducted at the Cook Plant
   delaying the restart of the units.  Previously, the units were
   scheduled to return to service at the end of the first and
   second quarters of 1999.  The decision to delay restart
   resulted from internal assessments that indicated a need to
   conduct expanded system readiness reviews.  A new restart
   schedule will be developed based on the results of the expanded
   reviews and should be available in June 1999.  When maintenance
   and other activities required for restart are complete, the
   Company will seek concurrence from the NRC to return the Cook
   Plant to service.  Until these additional reviews are
   completed, management is unable to determine when the units
   will be returned to service.

        In May 1999 the Company received a letter from the NRC
   indicating that NRC senior managers had identified Cook Plant
   as an "agency-focus plant."  The NRC senior managers concluded
   that continued agency-level oversight was appropriate; however,
   the NRC required no additional action to redirect Cook Plant
   activities.  The letter states that the NRC staff will continue
   to monitor Cook Plant performance through the Restart Panel
   process and evaluate whether additional action may be
   necessary.

        The cost of electricity supplied to retail customers
   remained higher due to the outage of the two Cook Plant nuclear
   units since higher cost coal-fired generation and coal based
   purchased power continue to be substituted for low cost nuclear
   generation.  The Indiana and Michigan retail jurisdictional
   fuel cost recovery mechanisms permit the recovery, subject to
   regulatory commission review and approval, of changes in fuel
   costs including the fuel component of purchased power in the
   Indiana jurisdiction and changes in replacement power in the
   Michigan jurisdiction.  Under these fuel cost recovery
   mechanisms, retail rates contain a fuel cost adjustment factor
   that reflects estimated fuel costs for the period during which
   the factor will be in effect subject to reconciliation to
   actual fuel costs in a future proceeding.  When actual fuel
   costs exceed the estimated costs reflected in the billing
   factor a regulatory asset is recorded and revenues are accrued. 
   Therefore, a regulatory asset has been recorded and revenues
   accrued in anticipation of the future reconciliation and
   billing under the fuel cost recovery mechanisms of the higher
   fuel costs to replace Cook energy during the extended outage. 
   At March 31, 1999, the regulatory asset was $118 million.

        On March 30, 1999, the IURC approved a settlement agreement
   that resolves all matters related to the reasonableness of fuel
   costs and all outage issues during the extended outage of the
   Cook Plant.  The settlement agreement provides for, among other
   things, a credit of $55 million, including interest, to Indiana
   retail customers; authorization to defer any unrecovered fuel
   revenues accrued between September 9, 1997 and December 31,
   1999, including the $52.3 million revenue portion of the $55
   million credit; authorization to defer up to $150 million of
   incremental operation and maintenance costs for the Cook Plant
   above the amount included in base rates; amortization of the
   fuel recoveries and non-fuel operation and maintenance cost
   deferrals over a five-year period ending December 31, 2003; a
   freeze in base rates through December 31, 2003; and a fixed
   fuel recovery charge through March 1, 2004.  The $55 million
   credit will be refunded through customers' bills  during the
   months of July, August and September 1999.

        The incremental costs incurred in first quarter 1999 for
   restart of the Cook units were $45 million of which $30 million
   were deferred pursuant to the settlement agreement discussed
   above.

        Unless the costs of the extended outage and restart efforts
   are recovered from customers, there would be a material adverse
   effect on results of operations, cash flows, and possibly
   financial condition.

   Other

        The Company continues to be involved in certain other
   matters discussed in the 1998 Annual Report.
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                      AND FINANCIAL CONDITION                   

            FIRST QUARTER 1999 vs. FIRST QUARTER 1998

RESULTS OF OPERATIONS
     Net income was unchanged in spite of the extended Cook Nuclear
Plant outage and the expiration of a major wholesale power
contract.
     Income statement line items which changed significantly were:          
                                                Increase     
                                              (in millions)   %

Revenues:
    Domestic Regulated Electric Utilities. .      $ 41        3
    Worldwide Non-regulated Operations . . .       132      N.M.
Maintenance and Other Operation Expense. . .        16        4
Worldwide Non-regulated Operations Expense .       108      N.M.
Interest and Preferred Dividends . . . . . .        26       25
Income Taxes . . . . . . . . . . . . . . . .        10       12

N.M. = Not Meaningful.

     Revenues from domestic regulated electric utility operations
increased primarily due to a 4% increase in retail sales.  Sales to
weather-sensitive residential and commercial customers increased
10% and 3%, respectively, reflecting colder winter weather in 1999. 
Domestic regulated electric utility wholesale revenues declined
reflecting the loss of a contract which supplied power to several
municipal customers.
     The increase in revenues from worldwide non-regulated
operations was predominantly due to the acquisitions of CitiPower,
an Australian electric distribution utility, and midstream
intrastate natural gas operations in December 1998.  These new
revenues were offset by an increase in worldwide non-regulated
operations expenses.
     Maintenance and other operation expense increased due to an
increase in nuclear engineering costs which were not subject to
deferral.  The increase in such costs were due to the extended
outage of the Cook Nuclear Plant which was shutdown in September
1997.
<PAGE>
     Worldwide non-regulated expenses increased as a result of the
expansion of business development activities and expenses from the
December 1998 acquisitions of CitiPower and the midstream gas
operations.
     Additional borrowings to fund the Company's non-regulated
operations, primarily the acquisitions of CitiPower and midstream
natural gas assets in December 1998, were the primary reason for
the significant increase in interest and preferred dividends.
     The increase in income taxes is primarily due to an increase
in United States (US) federal, state and local income taxes.  The
increase is due to a rise in pre-tax income primarily from domestic
regulated electric utility operations.
FINANCIAL CONDITION
     Total plant and property additions including capital leases for
the current period were $231 million.
     In April 1999 subsidiaries called $243 million of outstanding
first mortgage bonds for early redemption in May 1999. 
Consequently, the bonds were reclassified as a current liability on
the Consolidated Balance Sheets.
OTHER MATTERS
Spent Nuclear Fuel (SNF) Litigation
     As discussed in Management's Discussion and Analysis of Results
of Operations and Financial Condition (MDA) in the 1998 Annual
Report, as a result of the Department of Energy's (DOE) failure to
make sufficient progress toward a permanent repository or otherwise
assume responsibility for SNF, the Company along with a number of
unaffiliated utilities and states filed suit in the US Court of
Appeals for the District of Columbia Circuit requesting, among
other things, that the court order DOE to meet its obligations
under the law.  The court ordered the parties to proceed with
contractual remedies but declined to order DOE to begin accepting
SNF for disposal.  DOE estimates its planned site for the nuclear
waste will not be ready until 2010.  In June 1998, the Company
filed a complaint in the US Court of Federal Claims seeking damages
in excess of $150 million due to the DOE's partial material breach
of its unconditional contractual deadline to begin disposing of SNF
generated by the Cook Plant.  Similar lawsuits have been filed by
other utilities.  On April 6, 1999, the court granted DOE's motion
to dismiss a similar lawsuit filed by another utility.  Indiana
Michigan Power Company's case has been suspended pending final
resolution of the other utility's case.
Cook Nuclear Plant Shutdown
     As discussed in MDA in the 1998 Annual Report, management shut
down both units of the Cook Plant in September 1997 due to
questions, which arose during a Nuclear Regulatory Commission (NRC)
architect engineer design inspection, regarding the operability of
certain safety systems.  The NRC issued a Confirmatory Action
Letter in September 1997 requiring the Company to address certain
issues identified in the letter.  During 1998 the NRC notified the
Company that it had convened a Restart Panel for Cook Plant and
provided a list of required restart activities.  In order to
identify and resolve all issues, including those in the letter,
necessary to restart the Cook units, the Company is working with
the NRC and will be meeting with the Panel on a regular basis,
until the units are returned to service.
     In January 1999 the Company announced that additional
engineering reviews will be conducted at the Cook Plant delaying
the restart of the units.  Previously, the units were scheduled to
return to service at the end of the first and second quarters of
1999.  The decision to delay restart resulted from internal
assessments that indicated a need to conduct expanded system
readiness reviews.  A new restart schedule will be developed based
on the results of the expanded reviews and should be available in
June 1999.  When maintenance and other activities required for
restart are complete, the Company will seek concurrence from the
NRC to return the Cook Plant to service.  Until these additional
reviews are completed, management is unable to determine when the
units will be returned to service.
     In May 1999 the Company received a letter from the NRC
indicating that NRC senior managers had identified Cook Plant as an
"agency-focus plant."  The NRC senior managers concluded that
continued agency-level oversight was appropriate; however, the NRC
required no additional action to redirect Cook Plant activities. 
The letter states that the NRC staff will continue to monitor Cook
Plant performance through the Restart Panel process and evaluate
whether additional action may be necessary.
     The cost of electricity supplied to retail customers remained
higher due to the outage of the two Cook Plant nuclear units since
higher cost coal-fired generation and coal based purchased power
continue to be substituted for low cost nuclear generation.  The
Indiana and Michigan retail jurisdictional fuel cost recovery
mechanisms permit the recovery, subject to regulatory commission
review and approval, of changes in fuel costs including the fuel
component of purchased power in the Indiana jurisdiction and
changes in replacement power in the Michigan jurisdiction.  Under
these fuel cost recovery mechanisms, retail rates contain a fuel
cost adjustment factor that reflects estimated fuel costs for the
period during which the factor will be in effect subject to
reconciliation to actual fuel costs in a future proceeding.  When
actual fuel costs exceed the estimated costs reflected in the
billing factor a regulatory asset is recorded and revenues are
accrued.  Therefore, a regulatory asset has been recorded and
revenues accrued in anticipation of the future reconciliation and
billing under the fuel cost recovery mechanisms of the higher fuel
costs to replace Cook energy during the extended outage.  At March
31, 1999, this regulatory asset was $118 million.
     On March 30, 1999 the Indiana Utility Regulatory Commission
(IURC) approved a settlement agreement that resolves all matters
related to the reasonableness of fuel costs and all outage issues
during the extended outage of the Cook Plant.  The settlement
agreement provides for, among other things, a credit of $55
million, including interest, to Indiana retail customers;
authorization to defer any unrecovered fuel revenues accrued
between September 9, 1997 and December 31, 1999, including the
$52.3 million revenue portion of the $55 million credit;
authorization to defer up to $150 million of incremental operation
and maintenance costs for the Cook Plant above the amount included
in base rates; amortization of the fuel recoveries and non-fuel
operation and maintenance cost deferrals over a five-year period
ending December 31, 2003; a freeze in base rates through December
31, 2003; and a fixed fuel recovery charge through March 1, 2004. 
The $55 million credit will be refunded through customers' bills 
during the months of July, August and September 1999.
     The incremental costs incurred in first quarter of 1999 for
restart of the Cook units were $45 million of which $30 million
were deferred pursuant to the settlement agreement discussed above.
     Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect
on results of operations, cash flows, and possibly financial
condition.
Merger
     As discussed in MDA in the 1998 Annual Report, the Company and
Central and South West Corporation (CSW) announced plans to merge
in December 1997.  In 1998 the appropriate shareholder proposals
for the consummation of the merger were approved.  Approval of the
merger has been requested from the Federal Energy Regulatory
Commission (FERC), the Securities and Exchange Commission (SEC),
the NRC and all of CSW's state regulatory commissions: Arkansas,
Louisiana, Oklahoma and Texas.  In the near future, AEP and CSW
plan to make the final two filings associated with approval of the
merger with the Federal Communications Commission and the
Department of Justice.  The NRC and the Arkansas Public Service
Commission approved the merger in 1998.  In 1998 the FERC issued an
order which confirmed that a 250 megawatt 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.
     In 1998 the FERC issued an order establishing hearing
procedures for the merger and scheduled the hearings to begin on
June 1, 1999.  Subsequently, the FERC postponed the hearings until
June 29, 1999.  The 1998 FERC order indicated that the review of
the proposed merger will address the issues of competition, market
power and customer protection and instructed the companies to
refile an updated market power study.  On January 13, 1999, AEP and
CSW filed an updated market power study with the FERC.
     On May 11, 1999, the Oklahoma Corporation Commission (OCC)
approved the proposed merger between the Company and CSW.  The
approval follows an administrative law judge's oral decision on a
partial settlement between certain principal parties to the
Oklahoma merger proceeding which recommended that the OCC approve
the merger.  The partial settlement provides for sharing of net
merger savings with Oklahoma customers; no increase of Oklahoma
base rates prior to January 1, 2003; filing by December 31, 2001
with the FERC an application to join a regional transmission
organization; and implementing additional quality of service
standards for Oklahoma retail customers.  Oklahoma's share
(approximately $50 million) of net merger savings over the first
five years after the merger is consummated will be split between
Oklahoma customers and AEP shareholders, with customers receiving
approximately 55% of the net savings.  The partial settlement
agreement includes a recommendation by the OCC staff that the OCC
file with FERC indicating that it does not oppose the merger, but
reserves the right to ensure that there are no adverse impacts on
the Oklahoma transmission system.
     On May 4, 1999, AEP and CSW announced that a stipulated
settlement had been reached in Texas.  The agreement builds upon an
earlier settlement agreement signed by AEP, CSW and certain parties
to the Texas merger proceeding.  In addition to the parties that
were signatories to the earlier agreement, the staff of the Public
Utility Commission of Texas is a signatory to the new settlement as
well as other key parties to the merger proceeding.  The stipulated
settlement would result in rate reductions totaling $221 million
over a six-year period for Texas customers after the merger is
completed.  The $221 million rate reduction represents $84.4
million of net merger savings and $136.6 million to resolve
existing issues associated with CSW operating subsidiaries' rate
and fuel reconciliation proceedings in Texas.  Under the terms of
the settlement agreement, base rates would not be increased before
January 1, 2003 or three years after the merger, whichever is
later.  The settlement also calls for the divestiture of a total of
1,604 megawatts of existing and proposed generating capacity within
Texas.  If it is determined that the divestiture can proceed
immediately after the merger closes without jeopardizing pooling-of-interests
accounting treatment for the merger, sale of the
plants would begin no later than 90 days after the merger closes. 
Absent that determination, the divestiture would occur
approximately two years after the merger closes to satisfy the
requirements to use pooling-of-interests accounting treatment. 
Other provisions in the settlement agreement provide for, among
other things, accelerated stranded cost recovery, quality-of-service standards,
continuation of programs for disadvantaged
customers and transfer of control of bulk transmission facilities
to a regional transmission organization.
     The IURC approved a settlement agreement related to the merger
on April 26, 1999.  The settlement agreement resulted from an
investigation of the proposed merger between AEP and CSW initiated
by the IURC.  The terms of the settlement agreement provide for,
among other things, a sharing of net merger savings through
reductions in customers' bills of approximately $67 million over
eight years after the merger is completed; a one year extension
through January 1, 2005 of a freeze in base rates; additional
annual deposits of $5.5 million to the nuclear decommissioning
trust fund for the Indiana jurisdiction for the years 2001 through
2003; quality-of-service standards; and participation in a regional
transmission organization.  As part of the settlement agreement,
the IURC agreed not to oppose the merger in FERC or SEC 
proceedings.
     AEP and CSW reached a settlement with the local unions of the
International Brotherhood of Electrical Workers (IBEW) representing
employees of AEP and CSW.  Under the terms of the settlement, AEP
and CSW will not terminate any current IBEW employee as a result of
the merger and existing labor agreements will be recognized by the
merged company.  As part of the settlement, the IBEW local unions
will withdraw their opposition to completing the merger.
     On April 15, 1999, in compliance with a request from the staff
of the Kentucky Public Service Commission (KPSC) AEP filed an
application seeking KPSC approval for the indirect change in
control of Kentucky Power Company that will occur as a result of
the proposed merger.  AEP does not believe that the KPSC has the
jurisdictional authority to approve the merger.  Under the
governing statute the KPSC must act on the application within 60
days.  Therefore the KPSC proceeding is not expected to impact the
timing of the merger.
     In April 1999 AEP and CSW announced that settlements were
reached with certain wholesale customers that address issued
related to the proposed merger.  Under the terms of the settlements
the wholesale customers agreed not to oppose the merger in FERC or
SEC proceedings.
     The proposed merger of CSW into AEP would result in common
ownership of two United Kingdom (UK) regional electricity companies
(RECs), Yorkshire Power Group Limited (Yorkshire) and Seeboard,
plc.  AEP has a 50% ownership interest in Yorkshire and CSW has a
100% interest in Seeboard.  Although the merger of CSW into AEP is
not subject to approval by UK regulatory authorities, the common
ownership of two UK RECs could be referred by the UK Secretary of
State for Trade and Industry to the UK Competition Commission
(formerly Monopolies and Mergers Commission) for investigation.
     The merger is conditioned upon, among other things, the
approval of the above state and federal regulatory agencies.  The
transaction must satisfy many conditions, a number of which may not
be waived by the parties, including the condition that the merger
must be accounted for as a pooling of interests.  The merger
agreement will terminate on December 31, 1999 unless extended by
either party as provided in the merger agreement.  Although
consummation of the merger is expected to occur in the fourth
quarter of 1999, the Company is unable to predict the outcome or
the timing of the required regulatory proceedings
Virginia Restructuring
     In March 1999, a new law was enacted in Virginia to restructure
the electric utility industry.  Under the 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. 
Provisions allowing for an acceleration or limited delay in this
schedule are also contained in the law.  Except as provided in the
law, the generation of electricity will not be subject to rate
regulation after January 1, 2002.  Additionally, each Virginia
electric utility is required by 2001 to join or establish a
regional transmission entity which will manage and control
transmission assets.
     The Virginia restructuring law also provides an opportunity for
recovery of just and reasonable net stranded costs.  Stranded costs
are those costs above market including generation related net
regulatory assets and impaired tangible assets that potentially
would not be recoverable in a competitive market.  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. The capped
rates may be terminated after January 1, 2004, and prior to July 1,
2007, based upon the Virginia SCC determining that an effective
competitive market exists.  The wires charge will be equal to the
difference between the generation component of the capped rates and
the market price for generation service and will be imposed upon
departing customers through the expiration of the rate cap period.
     Management has reviewed all the evidence currently available
and concluded that as of March 31, 1999 the requirements to apply
Statement of Financial Accounting Standards (SFAS) 71, "Accounting
for the Effects of Certain Types of Regulation," continue to be met
for the Virginia retail jurisdiction.  The Company's Virginia rates
for generation will continue to be cost-based regulated until the
establishment of capped rates as provided in the law.  When capped
rates are established in Virginia, the application of SFAS 71 would
be discontinued for the Virginia retail jurisdiction portion of the
generating business.  At that time generation-related regulatory
assets applicable to the Virginia jurisdiction will be written off
to the extent that they cannot be recovered under the provisions of
the restructuring law and generating assets for the Virginia retail
jurisdiction will be evaluated for impairment.  An impairment loss
would be recorded to the extent that such assets cannot be
recovered through the transition recovery mechanisms provided by
the law.  The amount of regulatory assets applicable to the
Virginia generating business at March 31, 1999 is estimated to be
$61 million before related tax effects and any possible offsetting
regulatory liabilities.  Regulatory liabilities applicable to the
Virginia generation business at March 31, 1999 are estimated to be
$38 million of which $25 million represents deferred investment tax
credits (ITC).  The Company is evaluating the tax normalization
rules regarding the timing of the reversal of deferred ITC in
connection with the Virginia restructuring law and the ability to
record a reversal of deferred ITC in the same accounting periods
when any possible losses from unrecovered regulatory assets are
recorded.  Should it not be possible under the Virginia law to
recover all or a portion of the generation net regulatory  assets,
it could have a material adverse impact on results of operations;
however, the amount of any impairment loss for Virginia retail
jurisdictional generating assets and any loss from a possible
inability to recover generation net regulatory assets cannot be
estimated until such time as capped rates are determined under the
law.
Market Risks
     The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices, foreign
currency exchange rates and interest rates.  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, 1998.  Market risk represents the risk of loss
that may impact the Company due to adverse changes in commodity
market prices, foreign currency exchange rates and interest rates.
     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, 1998.
     The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at March 31, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
     On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date.  In
addition, certain systems may fail to detect that the year 2000 is
a leap year.  Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.

     Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Y2K-related failures and repair such failures if they occur.  This
includes both information technology (IT) systems, which are
mainframe and client server applications, and embedded logic
(non-IT) systems, such as process controls for energy production
and delivery.  Externally, the problem is being addressed with
entities that interact with the Company, including suppliers,
customers, creditors, financial service organizations and other
parties essential to the Company's operations.  In the course of
the external evaluation, the Company has sought written assurances
from third parties regarding their state of Y2K readiness.
     Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system. 
AEP, along with other electric utilities in North America,
regularly submits information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program. 
NERC then publicly reports summary information to the DOE regarding
the Y2K readiness of electric utilities.  AEP participated in an
industry-wide NERC-sponsored drill on April 9, 1999 simulating the
partial loss of voice and data communications.  There were no major
problems encountered with relaying information with the use of
backup telecommunications systems.  AEP and other utilities plan to
participate in a more comprehensive second NERC-sponsored drill on
September 8-9, 1999, to prepare for operations under Y2K
conditions.
     The NERC report, dated April 30, 1999 and entitled: Preparing
the Electric Power Systems of North America for Transition to the
Year 2000 - A Status Report and Work Plan, First Quarter 1999
states that: "With more than 75% of mission critical components
tested through March 31, 1999, findings in the field continue to
indicate that the transition through critical Y2K dates is expected
to have minimal impact on electric system operations in North
America."  The report also indicates that, "the risk of electrical
outages by Y2K appears to be no higher than the risks we already
experience" from incidents such as severe wind, ice, floods,
equipment failures and power shortages during an extremely hot or
cold period.
     Through the Electric Power Research Institute, an electric
utility industry-wide effort has been established to deal with Y2K
problems affecting embedded systems.  Under this effort,
participating utilities, including AEP, are working together to
assess specific vendors' system problems and test plans.
     The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.

     Company's State of Readiness - Work has been prioritized in
accordance with business risk.  The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
<PAGE>
     The following chart shows our progress toward becoming ready
for Y2K as of March 31, 1999:
                                 IT SYSTEMS              NON-IT  SYSTEMS     
                         COMPLETION                 COMPLETION
                         DATE/ESTIMATED   PERCENT   DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of      2/24/1998        100%      5/31/1998       100%
the Y2K activities
within the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment: 
Identifying all Company    7/31/1998        100%       2/15/1999     100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.

Remediation/Testing: The
process of modifying,      6/30/1999     Mainframe:    6/30/1999*     65%
replacing or retiring                    94%
those mission critical and                       
high priority digital-based
systems with problems                    Client
processing dates in the                  Server:
Year 2000. Testing these                 56%
systems to ensure that after             
modifications have been                  
implemented correct date                 
processing occurs and full
functionality has been maintained.

*The Company is upgrading its 800 MHZ trunked radio system, a mission critical
non-IT system, for Y2K readiness and it is anticipated that the upgrade should
be complete by September 30, 1999.

     The Company continues to make steady progress toward the June
30, 1999 target date and anticipates completing the
remediation/testing work for mission critical and high-priority
systems by the June 30, 1999 target date except as noted in the
table.
<PAGE>
     The above chart does not reflect progress of midstream gas
operations and CitiPower acquired in December 1998.  The mission
critical systems for the midstream gas operations are expected to
be ready by June 30, 1999 and the mission critical systems for
CitiPower are expected to be ready by October 1, 1999.

     Costs to Address the Company's Y2K Issues - Through March 31,
1999, the Company has spent $27 million on the Y2K project and
estimates spending an additional $29 million to $41 million to
achieve Y2K readiness.  Most Y2K costs are for software, IT
consultants and salaries and are expensed; however, in certain
cases the Company has acquired hardware that was capitalized.  The
Company intends to fund these expenditures through internal
sources.  Although significant, the cost of becoming Y2K compliant
is not expected to have a material impact on the Company's results
of operations, cash flows or financial condition.

     Risks of the Company's Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
     Automated power generation, transmission and distribution       
     systems
     Telecommunications systems
     Energy trading systems
     Time-in-use, demand and remote metering systems for
     commercial and industrial customers 
     Work management and billing systems.
     The potential problems related to erroneous processing by, or
failure of, these systems are:
     Power service interruptions to customers
     Interrupted revenue data gathering and collection
     Poor customer relations resulting from delayed billing and
     settlement.
     Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restorable in a reasonable
period of time.
     CitiPower operates under a legal and regulatory regime which
may expose it to customer claims, that may differ from claims under
the US legal and regulatory regime, for service interruptions
and/or power quality problems resulting from Y2K problems.
     In addition, although the Company is monitoring its
relationships with third parties, such as suppliers, customers and
other electric utilities, these third parties nonetheless represent
a risk that cannot be assessed with precision or controlled with
certainty.
     Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others not affiliated with AEP, fail for critical
applications, Y2K-related issues may materially adversely affect
AEP.

     Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a draft Y2K contingency plan
and submitted it to the East Central Area Reliability Council
(ECAR) in December 1998 as part of NERC's review of regional and
individual electric utility contingency plans in 1999.  NERC's
target date is June 1999 for the completion of this contingency
plan.  In addition, the Company intends to establish contingency
plans for its business units to address alternatives if Y2K related
failures occur.  These contingency plans will be developed by the
end of 1999.
     AEP's Y2K contingency plans build upon the disaster recovery,
system restoration, and contingency planning that we have had in
place and include:
     Availability of additional power generation reserves.
     Coal inventory of approximately 45 days of normal usage.
     Identifying critical operational locations, with key employees
     on duty at those locations during the Y2K transition.
<PAGE>
<PAGE>
<TABLE>
                        AEP GENERATING COMPANY
                         STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                              Three Months Ended
                                                                   March 31,      
                                                              1999           1998
                                                                 (in thousands)
<S>                                                          <C>            <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . .   $52,827        $54,052

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . .    20,258         22,501
  Rent - Rockport Plant Unit 2 . . . . . . . . . . . . . .    17,071         17,071
  Other Operation. . . . . . . . . . . . . . . . . . . . .     3,370          2,649
  Maintenance. . . . . . . . . . . . . . . . . . . . . . .     2,262          2,178
  Depreciation . . . . . . . . . . . . . . . . . . . . . .     5,440          5,412
  Taxes Other Than Federal Income Taxes. . . . . . . . . .     1,239            943
  Federal Income Taxes . . . . . . . . . . . . . . . . . .       827            962

          TOTAL OPERATING EXPENSES . . . . . . . . . . . .    50,467         51,716 

OPERATING INCOME . . . . . . . . . . . . . . . . . . . . .     2,360          2,336

NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . .       856            829

INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . .     3,216          3,165

INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . .       602            785

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .   $ 2,614        $ 2,380

                                                       

                    STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)

                                                               Three Months Ended
                                                                    March 31,      
                                                               1999           1998
                                                                  (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . .    $2,770         $2,528

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .     2,614          2,380

CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . . . .     1,073          3,176

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . .    $4,311         $1,732

                    

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,
                                                           1999            1998    
                                                              (in thousands)

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

  Production. . . . . . . . . . . . . . . . . . . . . .  $630,240        $630,260
  General . . . . . . . . . . . . . . . . . . . . . . .     2,068           2,009
  Construction Work in Progress . . . . . . . . . . . .     4,513           4,191

          Total Electric Utility Plant. . . . . . . . .   636,821         636,460

  Accumulated Depreciation. . . . . . . . . . . . . . .   283,005         277,855


          NET ELECTRIC UTILITY PLANT. . . . . . . . . .   353,816         358,605


CURRENT ASSETS:

  Cash and Cash Equivalents . . . . . . . . . . . . . .     2,010             232
  Accounts Receivable - Affiliated Companies. . . . . .    20,194          22,894
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . .    19,159          11,308
  Materials and Supplies. . . . . . . . . . . . . . . .     3,912           3,900
  Prepayments . . . . . . . . . . . . . . . . . . . . .        70             267


          TOTAL CURRENT ASSETS. . . . . . . . . . . . .    45,345          38,601


REGULATORY ASSETS . . . . . . . . . . . . . . . . . . .     5,924           5,984


DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . .     3,248             702 




            TOTAL . . . . . . . . . . . . . . . . . . .  $408,333        $403,892

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>                 AEP GENERATING COMPANY
                            BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                         March 31,     December 31,
                                                           1999            1998    
                                                              (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 . . . . . . . . . . . . . . . . . . .    33,235          35,235
  Retained Earnings . . . . . . . . . . . . . . . . . .     4,311           2,770
          Total Common Shareholder's Equity . . . . . .    38,546          39,005
  Long-term Debt. . . . . . . . . . . . . . . . . . . .    44,794          44,792

          TOTAL CAPITALIZATION. . . . . . . . . . . . .    83,340          83,797

OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . .       824             896

CURRENT LIABILITIES:
  Short-term Debt - Notes Payable . . . . . . . . . . .     5,575          24,450
  Accounts Payable:
    General . . . . . . . . . . . . . . . . . . . . . .     8,911           6,419
    Affiliated Companies. . . . . . . . . . . . . . . .     8,224           6,177
  Taxes Accrued . . . . . . . . . . . . . . . . . . . .     8,854           3,227
  Rent Accrued - Rockport Plant Unit 2. . . . . . . . .    23,427           4,963
  Other . . . . . . . . . . . . . . . . . . . . . . . .     4,808           6,023

          TOTAL CURRENT LIABILITIES . . . . . . . . . .    59,799          51,259


DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . .   131,937         133,330

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits . . . . . . . . . . .    65,724          66,562
  Amounts Due to Customers for Income Tax . . . . . . .    28,066          28,644

          TOTAL REGULATORY LIABILITIES. . . . . . . . .    93,790          95,206

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . .    38,643          39,404

            TOTAL . . . . . . . . . . . . . . . . . . .  $408,333        $403,892

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>                 AEP GENERATING COMPANY
                       STATEMENTS OF CASH FLOWS
<CAPTION>
                              (UNAUDITED)
                                                           Three Months Ended
                                                                March 31,       
                                                           1999           1998
                                                             (in thousands)
<S>                                                      <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . $  2,614       $  2,380
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . .    5,440          5,412
    Deferred Federal Income Taxes. . . . . . . . . . . .   (1,339)         1,446
    Deferred Investment Tax Credits. . . . . . . . . . .     (838)          (841)
    Amortization of Deferred Gain on Sale 
      and Leaseback - Rockport Plant Unit 2. . . . . . .   (1,393)        (1,393)
    Deferred Property Taxes. . . . . . . . . . . . . . .   (2,410)        (2,385)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable. . . . . . . . . . . . . . . . .    2,700          2,979 
    Fuel, Materials and Supplies . . . . . . . . . . . .   (7,863)        (3,821)
    Accounts Payable . . . . . . . . . . . . . . . . . .    4,539          4,119
    Taxes Accrued. . . . . . . . . . . . . . . . . . . .    5,627          2,716
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . .   18,464         18,464
  Other (net). . . . . . . . . . . . . . . . . . . . . .   (1,045)        (3,019)
        Net Cash Flows From Operating Activities . . . .   24,496         26,057

INVESTING ACTIVITIES - Net Cash Flows Used 
  for Construction . . . . . . . . . . . . . . . . . . .     (770)        (1,416)

FINANCING ACTIVITIES:
  Return of Capital to Parent Company. . . . . . . . . .   (2,000)          -    
  Retirement of Long-term Debt . . . . . . . . . . . . .     -           (25,000)
  Change in Short-term Debt (net). . . . . . . . . . . .  (18,875)         3,425 
  Dividends Paid . . . . . . . . . . . . . . . . . . . .   (1,073)        (3,176)
        Net Cash Flows Used For Financing Activities . .  (21,948)       (24,751)

Net Increase (Decrease) in Cash and Cash Equivalents . .    1,778           (110)
Cash and Cash Equivalents at Beginning of Period . . . .      232            237
Cash and Cash Equivalents at End of Period . . . . . . . $  2,010       $    127

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $470,000 and $982,000 in
1999 and 1998, respectively, and for income taxes was $15,000 in 1998.

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
                        AEP GENERATING COMPANY
                     NOTES TO FINANCIAL STATEMENTS
                             MARCH 31, 1999                
                              (UNAUDITED)

1.   GENERAL

     The accompanying unaudited financial statements should be read in
conjunction with the 1998 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.

<PAGE>
<PAGE>                  AEP GENERATING COMPANY
       MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

               FIRST QUARTER 1999 vs. FIRST QUARTER 1998


     Operating revenues are derived from the sale of Rockport Plant
energy and capacity to two affiliated companies and one unaffiliated
utility pursuant to Federal Energy Regulatory Commission (FERC) approved
long-term unit power agreements.  The unit power agreements provide for
recovery of the cost of producing the power including a FERC approved
rate of return on common equity and a return on other capital net of
temporary cash investments.  A monthly power bill for energy supplied
is issued based on estimated expenses for the month and adjusted to
actual amounts in the following month.
     Net income increased $0.2 million or 10% primarily as a result of
the use of estimates for power production operation and maintenance
expenses to bill customers which were in excess of the actual expenses
incurred and included in the Statements of Income.  The estimates will
be adjusted to actual amounts in the customers' April bills.
     Income statement line items which changed significantly were:        
                                            Increase (Decrease)
                                              (in millions)   %

Operating Revenues                                $(1.2)      (2)
Fuel Expense                                       (2.2)     (10)
Other Operation Expense                             0.7       27
Taxes Other Than Federal Income Taxes               0.3       31
Federal Income Taxes                               (0.1)     (14)
Interest Charges                                   (0.2)     (23)

     The decrease in operating revenues reflects recovery of lower
operating expenses primarily reduced fuel expense.
     Fuel expense decreased due to a reduction in generation in the first
quarter of 1999 as a result of reduced availability of the Rockport
Plant.  In 1999 outages of the Rockport Plant units were of longer
duration than in 1998 causing the reduction in Rockport Plant
availability.
<PAGE>
     The increase in other operation expense is primarily due to the
Company's allocated share of Rockport Plant's employee severance expense
incurred in 1999 in excess of amounts accrued at December 31, 1998 and
a payment to the City of Rockport in settlement of an annexation issue.
     Taxes other than federal income taxes increased due to an increase
in state income taxes which resulted from an increase in pre-tax
operating income in 1999 due to the cessation of tax depreciation for
Rockport Plant Unit 1.
     The decline in federal income taxes attributable to operations was
due to the reversal of deferred taxes in excess of the statutory tax
rate partially offset by an increase in pre-tax operating income.
     Interest charges decreased due to a reduction in outstanding long-term debt
balances reflecting the redemption of $25 million in March
1998 of pollution control revenue bonds.
<PAGE>
<PAGE>
<TABLE>
              APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                             Three Months Ended
                                                                  March 31,      
                                                             1999           1998
                                                               (in thousands)
<S>                                                         <C>          <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . .  $427,702     $415,366

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . .   123,573      108,209
  Purchased Power. . . . . . . . . . . . . . . . . . . . .    50,591       69,262
  Other Operation. . . . . . . . . . . . . . . . . . . . .    62,749       54,867
  Maintenance. . . . . . . . . . . . . . . . . . . . . . .    28,511       35,352
  Depreciation and Amortization. . . . . . . . . . . . . .    36,551       35,405
  Taxes Other Than Federal Income Taxes. . . . . . . . . .    29,975       30,244
  Federal Income Taxes . . . . . . . . . . . . . . . . . .    24,145       17,778
          TOTAL OPERATING EXPENSES . . . . . . . . . . . .   356,095      351,117
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . .    71,607       64,249
NONOPERATING LOSS. . . . . . . . . . . . . . . . . . . . .    (1,088)        (387)
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . .    70,519       63,862
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . .    31,258       30,663
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .    39,261       33,199
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . .       675          469
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . .  $ 38,586     $ 32,730


                                                               


             CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)
                                                             Three Months Ended
                                                                  March 31,      
                                                             1999           1998
                                                               (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . .  $179,461     $207,544
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .    39,261       33,199

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . . . . . . . . . .    30,348       29,729
    Cumulative Preferred Stock . . . . . . . . . . . . . .       567          362
  Capital Stock Expense. . . . . . . . . . . . . . . . . .       108          107

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . .  $187,699     $210,545


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,
                                                            1999            1998    
                                                              (in thousands)
ASSETS
<S>                                                      <C>             <C> 
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .   $1,996,848      $1,979,180
  Transmission . . . . . . . . . . . . . . . . . . . .    1,122,987       1,118,726
  Distribution . . . . . . . . . . . . . . . . . . . .    1,650,705       1,641,523
  General. . . . . . . . . . . . . . . . . . . . . . .      229,512         228,464
  Construction Work in Progress. . . . . . . . . . . .      121,376         119,466
          Total Electric Utility Plant . . . . . . . .    5,121,428       5,087,359
  Accumulated Depreciation and Amortization. . . . . .    2,018,326       1,984,856

          NET ELECTRIC UTILITY PLANT . . . . . . . . .    3,103,102       3,102,503



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .      120,748         111,020



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .       36,098           7,755
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .       88,504         122,746
    Affiliated Companies . . . . . . . . . . . . . . .       23,084          35,802
    Miscellaneous. . . . . . . . . . . . . . . . . . .        9,335           8,572
  Allowance for Uncollectible Accounts . . . . . . . .       (2,487)         (2,234)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .       54,937          49,826
  Materials and Supplies . . . . . . . . . . . . . . .       61,128          60,440
  Accrued Utility Revenues . . . . . . . . . . . . . .       35,008          45,985
  Energy Marketing and Trading Contracts . . . . . . .      138,195          22,436
  Prepayments. . . . . . . . . . . . . . . . . . . . .       14,499           8,151

          TOTAL CURRENT ASSETS . . . . . . . . . . . .      458,301         359,479



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .      424,314         433,516



DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .       43,529          40,520

            TOTAL. . . . . . . . . . . . . . . . . . .   $4,149,994      $4,047,038

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
              APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                        March 31,      December 31,
                                                          1999             1998    
                                                              (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. . . . . . . . . . . . . . . . . .      663,743          663,633
  Retained Earnings. . . . . . . . . . . . . . . . .      187,699          179,461
          Total Common Shareholder's Equity. . . . .    1,111,900        1,103,552
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . .       19,353           19,359
    Subject to Mandatory Redemption. . . . . . . . .       22,310           22,310
  Long-term Debt . . . . . . . . . . . . . . . . . .    1,395,477        1,472,451

          TOTAL CAPITALIZATION . . . . . . . . . . .    2,549,040        2,617,672

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . .      123,043          120,281

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . .      157,239           80,004
  Short-term Debt. . . . . . . . . . . . . . . . . .       57,275           76,400
  Accounts Payable . . . . . . . . . . . . . . . . .       97,080          110,882
  Taxes Accrued. . . . . . . . . . . . . . . . . . .       50,421           35,719
  Customer Deposits. . . . . . . . . . . . . . . . .       13,537           14,123
  Interest Accrued . . . . . . . . . . . . . . . . .       29,288           19,990
  Revenue Refunds Accrued. . . . . . . . . . . . . .       44,818           95,267
  Energy Marketing and Trading Contracts . . . . . .      138,960           24,076
  Other. . . . . . . . . . . . . . . . . . . . . . .       84,242           78,808

          TOTAL CURRENT LIABILITIES. . . . . . . . .      672,860          535,269

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . .      653,896          643,711

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . .       61,059           62,231

DEFERRED CREDITS . . . . . . . . . . . . . . . . . .       90,096           67,874

CONTINGENCIES (Note 6)

            TOTAL. . . . . . . . . . . . . . . . . .   $4,149,994       $4,047,038

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,      
                                                              1999          1998
                                                                (in thousands)
<S>                                                        <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . $  39,261     $  33,199
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . .    36,814        35,731
    Deferred Federal Income Taxes. . . . . . . . . . . . .    12,362        (2,138)
    Deferred Investment Tax Credits. . . . . . . . . . . .    (1,172)       (1,182)
    Deferred Power Supply Costs (net). . . . . . . . . . .    14,706         7,390
    Provision for Revenue Refunds. . . . . . . . . . . . .      -           14,965
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . .    46,450        (4,682)
    Fuel, Materials and Supplies . . . . . . . . . . . . .    (5,799)       (2,968)
    Accrued Utility Revenues . . . . . . . . . . . . . . .    10,977        15,450
    Prepayments. . . . . . . . . . . . . . . . . . . . . .    (6,348)          465
    Accounts Payable . . . . . . . . . . . . . . . . . . .   (13,802)      (15,103)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . .    14,702        23,570
    Interest Accrued . . . . . . . . . . . . . . . . . . .     9,298         8,780
  Other (net). . . . . . . . . . . . . . . . . . . . . . .   (41,060)      (14,392)

        Net Cash Flows From Operating Activities . . . . .   116,389        99,085


INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . .   (38,129)      (40,066)
  Proceeds from Sale of Property . . . . . . . . . . . . .       127           535

        Net Cash Flows Used For Investing Activities . . .   (38,002)      (39,531)


FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . .      -           96,781
  Change in Short-term Debt (net). . . . . . . . . . . . .   (19,125)       12,100
  Retirement of Cumulative Preferred Stock . . . . . . . .        (4)         (117)
  Retirement of Long-term Debt . . . . . . . . . . . . . .      -         (138,470)
  Dividends Paid on Common Stock . . . . . . . . . . . . .   (30,348)      (29,729)
  Dividends Paid on Cumulative Preferred Stock . . . . . .      (567)         (572)
        Net Cash Flows Used For Financing Activities . . .   (50,044)      (60,007)

Net Increase (Decrease) in Cash and Cash Equivalents . . .    28,343          (453)
Cash and Cash Equivalents at Beginning of Period . . . . .     7,755         6,947
Cash and Cash Equivalents at End of Period . . . . . . . . $  36,098     $   6,494

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $21,009,000 and $20,933,000
  and  for income taxes  was $57,000 and  $570,000 in  1999 and 1998, respectively.
  Noncash  acquisitions under capital leases were $2,453,000 and $6,120,000 in 1999
  and 1998, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
              APPALACHIAN POWER COMPANY AND SUBSIDIARIES
              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                            MARCH 31, 1999              
                              (UNAUDITED)
1.   GENERAL

          The accompanying unaudited consolidated financial statements
     should be read in conjunction with the 1998 Annual Report as
     incorporated in and filed with the Form 10-K.  Certain prior-period
     amounts have been reclassified to agree with 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 April 1999 the Company called $77 million of first mortgage
     bonds, $37 million of 8.43% series due 2022, $30 million of 7.90%
     series due 2023 and $10 million of 7.80% series due 2023, for early
     redemption in May.  Consequently, the bonds were reclassified as a
     current liability on the Consolidated Balance Sheets.

3.   VIRGINIA RESTRUCTURING

          As discussed in Note 2 of the Notes to Consolidated Financial
     Statements in the 1998 Annual Report, in February 1999 the Virginia
     legislature passed comprehensive legislation, which became law upon
     the Governor's signature in March  1999, to restructure the electric
     utility industry.  Under the 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.  Provisions allowing for an
     acceleration or limited delay in this schedule are also contained
     in the law.  Except as provided in the law, the generation of
     electricity will not be subject to rate regulation after January 1,
     2002.  Additionally, each Virginia electric utility is required by
     2001 to join or establish a regional transmission entity which will
     manage and control transmission assets.

          The Virginia restructuring law also provides an opportunity for
     recovery of just and reasonable net stranded costs.  Stranded costs
     are those costs above market including generation related net
     regulatory assets and impaired tangible assets that potentially
     would not be recoverable in a competitive market.  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. The capped rates may be
     terminated after January 1, 2004, and prior to July 1, 2007, based
     upon the Virginia SCC determining that an effective competitive
     market exists.  The wires charge will be equal to the difference
     between the generation component of the capped rates and the market
     price for generation service and will be imposed upon departing
     customers through the expiration of the rate cap period.

          Management has reviewed all the evidence currently available and
     concluded that as of March 31, 1999 the requirements to apply
     Statement of Financial Accounting Standards (SFAS) 71, "Accounting
     for the Effects of Certain Types of Regulation," continue to be met. 
     The Company's Virginia rates for generation will continue to be
     cost-based regulated until the establishment of capped rates as
     provided in the law.  When capped rates are established in Virginia,
     the application of SFAS 71 would be discontinued for the Virginia
     retail jurisdiction portion of the generating business.  At that
     time generation-related regulatory assets applicable to the Virginia
     jurisdiction will have to be written off to the extent that they
     cannot be recovered under the provisions of the restructuring law
     and generating assets for the Virginia retail jurisdiction will have
     to be evaluated for impairment.  An impairment loss would be
     recorded to the extent that such assets cannot be recovered through
     the transition recovery mechanisms provided by the law.  The amount
     of regulatory assets applicable to the Virginia generating business
     at March 31, 1999 is estimated to be $61 million before related tax
     effects and any possible offsetting regulatory liabilities. 
     Regulatory liabilities applicable to the Virginia generation
     business at March 31, 1999 are estimated to be $38 million of which
     $25 million represents deferred investment tax credits (ITC).  The
     Company is evaluating the tax normalization rules regarding the
     timing of the reversal of deferred ITC in connection with the
     Virginia restructuring law and the ability to record a reversal of
     deferred ITC in the same accounting periods when any possible losses
     from unrecovered regulatory assets are recorded.  Should it not be
     possible under the Virginia law to recover all or a portion of the
     generation net regulatory  assets, it could have a material adverse
     impact on results of operations; however, the amount of any
     impairment loss for Virginia retail jurisdictional generating assets
     and any loss from a possible inability to recover generation net
     regulatory assets cannot be estimated until such time as capped
     rates are determined under the law.

4.   RATE MATTERS

     Virginia Jurisdiction

          As discussed in Note 3 of the Notes to Consolidated Financial
     Statements in the 1998 Annual Report, the Company and the staff of
     the Virginia SCC filed a settlement agreement with the Virginia SCC
     in January 1999.  The settlement agreement was approved by the
     Virginia SCC in February 1999.  It required a refund to customers
     of all amounts collected in excess of the settlement rates.  In
     February 1999 new rates were implemented, and in March 1999 refunds
     of $48.8 million including interest were made to customers.  A
     liability for the refunds and interest had previously been recorded
     by the Company.

     Wholesale Jurisdiction

          As discussed in Note 3 of the Notes to Consolidated Financial
     Statements in the 1998 Annual Report, the Company had requested a
     rehearing of a June 1998 Federal Energy Regulatory Commission (FERC)
     order which granted an annual rate increase of $3.4 million in
     response to a request for an $8.7 million annual rate increase.  The
     FERC had authorized the Company to implement the $8.7 million annual
     rate increase subject to refund in 1992.  On April 5, 1999, the FERC
     denied the rehearing request.  As a result the Company will make the
     refund to customers following FERC approval of the Company's
     compliance filing of proposed new rates as ordered by the FERC.  A
     refund liability of $44.4 million, including interest, has been
     accrued.

     West Virginia Jurisdiction

          On May 12, 1999, the Company filed with the West Virginia Public
     Service Commission for a base rate increase of $50.3 million
     annually and a reduction in expanded net energy cost rates of $37.9
     million annually.  The filings request that the new rates become
     effective January 1, 2000 when the current rate freeze expires.

5.   NEW ACCOUNTING STANDARDS

          In the first quarter of 1999 the Company adopted the Financial
     Accounting Standards Board's Emerging Issues Task Force Consensus
     (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
     and Risk Management Activities". The EITF requires that all energy
     trading contracts be marked-to-market.  The effect on the
     Consolidated Statements of Income of marking open trading contracts
     to market is deferred as regulatory assets or liabilities for the
     portion of open trading transactions that are included in cost of
     service on a settlement basis for ratemaking purposes in the
     Company's non-Virginia jurisdictions.  The Virginia jurisdiction net
     mark-to-market pre-tax gain of $1.5 million for the first quarter
     of 1999 is included in net income as a result of an agreed
     prohibition against establishing regulatory assets in a February
     1999 Virginia SCC ordered settlement agreement.  The adoption of the
     EITF did not have a material effect on results of operations, cash
     flows or financial condition.

6.   CONTINGENCIES

     Litigation

          As discussed in Note 4 of the Notes to Consolidated Financial
     Statements in the 1998 Annual Report, the deductibility of certain
     interest deductions related to American Electric Power's corporate
     owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through
     March 31, 1999 would reduce earnings by approximately $79 million
     (including interest).  The Company has made no provision for any
     possible earnings impact from this matter.

          In 1998 the Company made payments of taxes and interest
     attributable to COLI interest deductions for taxable years 1991-1997
     to avoid the potential assessment by the IRS of any additional above
     market rate interest on the contested amount. These payments to the
     IRS are included on the Consolidated Balance Sheets in other
     property and investments pending the resolution of this matter.  The
     Company will seek refund, either administratively or through
     litigation, of all amounts paid plus interest.

          In order to resolve this issue, the Company filed suit against
     the United States in the US District Court for the Southern District
     of Ohio in March 1998.  Management believes that it has a
     meritorious position and will vigorously pursue this lawsuit.  In
     the event the resolution of this matter is unfavorable, it will have
     a material adverse impact on results of operations.

          The Company continues to be involved in certain other matters
     discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
              APPALACHIAN POWER COMPANY AND SUBSIDIARIES
     MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                        AND FINANCIAL CONDITION                   

               FIRST QUARTER 1999 vs. FIRST QUARTER 1998

RESULTS OF OPERATIONS
     Net income increased $6.1 million or 18% as a result of increased
retail sales reflecting colder winter weather and a favorable accrual
adjustment to a revenue refund provision, partially offset by decreased
wholesale sales reflecting the loss of certain wholesale customers. 
Income statement line items which changed significantly were:              
                                             Increase (Decrease)
                                              (in millions)   %

     Operating Revenues. . . . . . . . . .        $ 12.3        3
     Fuel Expense. . . . . . . . . . . . .          15.4       14 
     Purchased Power Expense . . . . . . .         (18.7)     (27)
     Other Operation Expense . . . . . . .           7.9       14
     Maintenance Expense . . . . . . . . .          (6.8)     (19)
     Federal Income Taxes. . . . . . . . .           6.4       36

     The increase in operating revenues is attributable to a 5% increase
in retail revenues, reflecting increased sales to residential customers
of 15% due to colder winter weather, and the effect of a favorable
adjustment to a provision for revenue refunds in the Company's Virginia
jurisdiction in connection with the execution of the refund.  A 26%
reduction in wholesale revenues, reflecting the loss of a contract which
supplied power to several municipal customers, partly offset the
increase in retail revenues.
     The increase in fuel expense was primarily due to an increase in
generation to meet the increased retail demand for electricity.
     Purchased power expense decreased due to a decrease in purchases of
energy from the American Electric Power (AEP) System Power Pool (AEP
Power Pool).
     The increase in other operation expense primarily reflects an
increase in employee benefit costs as a result of incentive compensation
plan accrual adjustments in connection with the payment of such
compensation, which adjustments were unfavorable in 1999 and favorable
in 1998, and an increase in workers' compensation accruals.
<PAGE>
     Maintenance expense decreased significantly due to reduced
expenditures resulting from costs incurred in 1998 to repair overhead
transmission and distribution lines following two severe snowstorms.
     The increase in federal income tax expense attributable to
operations was primarily due to an increase in pre-tax operating income
and changes in certain book/tax differences accounted for on a flow-through
basis for rate-making purposes.

FINANCIAL CONDITION
     Total plant and property additions including capital leases for the
first three months of 1999 were $41 million.  Short-term debt decreased
by $19 million during the quarter.
     In April 1999 the Company called $77 million of first mortgage
bonds, $37 million of 8.43% series due 2022, $30 million of 7.90% series
due 2023 and $10 million of 7.80% series due 2023, for early redemption
in May.  Consequently, the bonds were reclassified as a current
liability on the Consolidated Balance Sheets.
OTHER MATTERS
Virginia Restructuring
     As discussed in Management's Discussion and Analysis of Results of
Operations and Financial Condition in the 1998 Annual Report, in
February 1999 the Virginia legislature passed comprehensive legislation,
which became law in March 1999, to restructure the electric utility
industry in Virginia.  Under the 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.  Provisions allowing for an acceleration or limited
delay in this schedule are also contained in the law.  Except as
provided in the law, the generation of electricity will not be subject
to rate regulation after January 1, 2002.  Additionally, each Virginia
electric utility is required by 2001 to join or establish a regional
transmission entity which will manage and control transmission assets.
<PAGE>
     The Virginia restructuring law also provides an opportunity for
recovery of just and reasonable net stranded costs.  Stranded costs are
those costs above market including generation related net regulatory
assets and impaired tangible assets that potentially would not be
recoverable in a competitive market.  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.
The capped rates may be terminated after January 1, 2004, and prior to
July 1, 2007, based upon the Virginia SCC determining that an effective
competitive market exists.  The wires charge will be equal to the
difference between the generation component of the capped rates and the
market price for generation service and will be imposed upon departing
customers through the expiration of the rate cap period.
     Management has reviewed all the evidence currently available and
concluded that as of March 31, 1999 the requirements to apply Statement
of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects
of Certain Types of Regulation," continue to be met.  The Company's
Virginia rates for generation will continue to be cost-based regulated
until the establishment of capped rates as provided in the law.  When
capped rates are established in Virginia, the application of SFAS 71
would be discontinued for the Virginia retail jurisdiction portion of
the generating business, generation-related regulatory assets applicable
to the Virginia jurisdiction will have to be written off to the extent
that they cannot be recovered under the provisions of the restructuring
law and generating assets for the Virginia retail jurisdiction will have
to be evaluated for impairment.  An impairment loss would be recorded
to the extent that such assets cannot be recovered through the
transition recovery mechanisms provided by the law.  The amount of
regulatory assets applicable to the Virginia generating business at
March 31, 1999 is estimated to be $61 million before related tax effects
and any possible offsetting regulatory liabilities.  Regulatory
liabilities applicable to the Virginia generation business at March 31,
1999 are estimated to be $38 million of which $25 million represents
deferred investment tax credits (ITC).  The Company is evaluating the
tax normalization rules regarding the timing of the reversal of deferred
ITC in connection with the Virginia restructuring law and the ability
to record a reversal of deferred ITC in the same accounting periods when
any possible losses from unrecovered regulatory assets are recorded. 
Should it not be possible under the Virginia law to recover all or a
portion of the generation net regulatory  assets, it could have a
material adverse impact on results of operations; however, the amount
of any impairment loss for Virginia retail jurisdictional generating
assets and any loss from a possible inability to recover net generation
regulatory assets cannot be estimated until such time as capped rates
are determined under the law.
Market Risks
     The Company has certain market risks inherent in its business
activities 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 AEP Power Pool, has not changed
materially since December 31, 1998.  Market risk represents the risk of
loss that may impact the Company due to adverse changes in commodity
market prices and interest rates.
     The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at March 31, 1999 is not materially
different than at December 31, 1998.

Year 2000 (Y2K) Readiness Disclosure
     On or about midnight on December 31, 1999, digital computing systems
may begin to produce erroneous results or fail, unless these systems are
modified or replaced, because such systems may be programmed incorrectly
and interpret the date of January 1, 2000 as being January 1st of the
year 1900 or another incorrect date.  In addition, certain systems may
fail to detect that the year 2000 is a leap year.  Problems can also
arise earlier than January 1, 2000, as dates in the next millennium are
entered into non-Y2K ready programs.

Readiness Program - Internally, the Company, through the AEP System, is
modifying or replacing its computer hardware and software programs to
minimize Y2K-related failures and repair such failures if they occur. 
This includes both information technology (IT) systems, which are
mainframe and client server applications, and embedded logic (non-IT)
systems, such as process controls for energy production and delivery. 
Externally, the problem is being addressed with entities that interact
with the Company, including suppliers, customers, creditors, financial
service organizations and other parties essential to the Company's
operations.  In the course of the external evaluation, the Company has
sought written assurances from third parties regarding their state of
Y2K readiness.
     Another issue we are addressing is the impact of electric power grid
problems that may occur outside of our transmission system.  The
Company, along with other electric utilities in North America, regularly
submits information to the North American Electric Reliability Council
(NERC) as part of NERC's Y2K readiness program.  NERC then publicly
reports summary information to the U.S. Department of Energy (DOE)
regarding the Y2K readiness of electric utilities.  AEP participated in
an industry-wide NERC-sponsored drill on April 9, 1999 simulating the
partial loss of voice and data communications.  There were no major
problems encountered with relaying information with the use of backup
telecommunications systems.  AEP and other utilities plan to participate
in a more comprehensive second NERC-sponsored drill on September 8-9,
1999, to prepare for operations under Y2K conditions.
     The NERC report, dated April 30, 1999 and entitled: Preparing the
Electric Power Systems of North America for Transition to the Year 2000
- A Status Report and Work Plan, First Quarter 1999, states that: "With
more than 75% of mission critical components tested through March 31,
1999, findings in the field continue to indicate that the transition
through critical Y2K dates is expected to have minimal impact on
electric system operations in North America."  The report also indicates
that, "the risk of electrical outages by Y2K appears to be no higher
than the risks we already experience" from incidents such as severe
wind, ice, floods, equipment failures and power shortages during an
extremely hot or cold period.
     Through the Electric Power Research Institute, an electric utility
industry-wide effort has been established to deal with Y2K problems
affecting embedded systems.  Under this effort, participating utilities
are working together to assess specific vendors' system problems and
test plans.
     The state regulatory commissions in the Company's service territory
are also reviewing the Y2K readiness of the Company.

Company's State of Readiness - Work has been prioritized in accordance
with business risk.  The highest priority has been assigned to
activities that potentially affect safety, the physical generation and
delivery of energy, and communications; followed by back office
activities such as customer service/billing, regulatory reporting,
internal reporting and administrative activities (e.g., payroll,
procurement, accounts payable); and finally, those activities that would
cause inconvenience or productivity loss in normal business operations.
<PAGE>
     The following chart shows our progress toward becoming ready for the
Y2K as of March 31, 1999:
                                 IT SYSTEMS              NON-IT  SYSTEMS     
                         COMPLETION                 COMPLETION
                         DATE/ESTIMATED   PERCENT   DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of      2/24/1998        100%      5/31/1998       100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment: 
Identifying all Company    7/31/1998        100%       2/15/1999     100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.

Remediation/Testing: The
process of modifying,      6/30/1999     Mainframe:    6/30/1999*     65%
replacing or retiring                    94%
those mission critical and                       
high priority digital-based
systems with problems                    Client
processing dates in the                  Server:
Year 2000. Testing these                 56%
systems to ensure that after             
modifications have been                  
implemented correct date                 
processing occurs and full
functionality has been maintained.

*The Company is upgrading its 800 MHZ trunked radio system, a mission
critical non-IT system, for Y2K readiness and it is anticipated that the 
upgrade should be complete by September 30, 1999.

The Company continues to make steady progress toward the June 30, 1999 target
date and anticipates completing the remediation/testing work for mission 
critical and high-priority systems by the June 30, 1999 target date except as
noted in the table.

Costs to Address the Company's Year 2000 Issues - Through March 31, 1999, the
Company has spent $8 million on the Y2K project and, estimates spending an 
additional $9 million to $12 million to achieve Y2K readiness.  Most Y2K 
costs are for software modifications, IT consultants and salaries and are
expensed; however, in certain cases the Company has acquired hardware that was
capitalized.  The Company intends to fund these expenditures through 
internal sources.  Although significant, the cost of becoming Y2K compliant
is not expected to have a material impact on the Company's results of
operations, cash flows or financial condition.

Risks of the Company's Y2K Issues - The applications posing the greatest 
business risk to the Company's operations should they experience Y2K
 problems are:
     Automated power generation, transmission and distribution systems
     Telecommunications systems
     Energy trading systems
     Time-in-use, demand and remote metering systems for commercial 
     and industrial customers and
     Work management and billing systems.
     The potential problems related to erroneous processing by, or failure 
     of, these systems are:

     Power service interruptions to customers
     Interrupted revenue data gathering and collection
     Poor customer relations resulting from delayed billing and
     settlement.
     Although it is difficult to hypothesize a most reasonably likely worst 
     case Y2K scenario with any degree of certainty, management believes that
     such a scenario would be small, localized interruptions of service, 
     which would be restorable in a reasonable period of time.

     In addition, although relationships with third parties, such as suppliers,
customers and other electric utilities, are being monitored, these third parties
nonetheless represent a risk that cannot be assessed with precision or 
controlled with certainty.
     Due to the complexity of the problem and the interdependent nature of 
computer systems, if our corrective actions, and/or the actions of others 
who impact the AEP System's operations but are not affiliated with the AEP 
System, fail for critical applications, Y2K-related issues may materially
adversely affect the Company.

<PAGE>
Company's Contingency Plans - To address possible failures of electric 
generation and delivery of electrical energy due to Y2K related failures, 
we have established a draft Y2K contingency plan and submitted it to the
East Central Area Reliability Council in
December 1998 as part of NERC's review of regional and individual electric
utility contingency plans in 1999.  NERC's target date is June 1999 for the
completion of this contingency plan.  In addition, the Company intends to 
establish contingency plans for its business units to address alternatives
if Y2K related failures occur.  Contingency plans will be developed by the 
end of 1999.
     The Company's plans build upon the disaster recovery, system restoration,
and contingency planning that we have had in place and include:
     Availability of additional power generation reserves.
     Coal inventory of approximately 45 days of normal usage.
     Identifying critical operational locations, with key employees on duty at
     those locations during the Y2K transition.
<PAGE>
<PAGE>
<TABLE>    COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                               Three Months Ended
                                                                    March 31,       
                                                               1999           1998
                                                                 (in thousands)
<S>                                                         <C>            <C> 
OPERATING REVENUES . . . . . . . . . . . . . . . . . . .    $279,067       $266,399

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . .      45,856         46,980
  Purchased Power. . . . . . . . . . . . . . . . . . . .      55,191         47,837
  Other Operation. . . . . . . . . . . . . . . . . . . .      45,969         44,582
  Maintenance. . . . . . . . . . . . . . . . . . . . . .      13,946         14,307
  Depreciation . . . . . . . . . . . . . . . . . . . . .      23,184         22,850
  Taxes Other Than Federal Income Taxes. . . . . . . . .      31,078         29,936
  Federal Income Taxes . . . . . . . . . . . . . . . . .      17,796         14,678

         TOTAL OPERATING EXPENSES. . . . . . . . . . . .     233,020        221,170

OPERATING INCOME . . . . . . . . . . . . . . . . . . . .      46,047         45,229

NONOPERATING INCOME (LOSS) . . . . . . . . . . . . . . .         361            (28)

INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . .      46,408         45,201

INTEREST CHARGES . . . . . . . . . . . . . . . . . . . .      18,990         19,556

NET INCOME . . . . . . . . . . . . . . . . . . . . . . .      27,418         25,645

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

EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . .    $ 26,885       $ 25,112

                                                                

             CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)

                                                              Three Months Ended
                                                                   March 31,       
                                                               1999          1998
                                                                 (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . .    $186,441       $138,172

NET INCOME . . . . . . . . . . . . . . . . . . . . . . .      27,418         25,645

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . . . . . . . . .      21,999         20,661
    Cumulative Preferred Stock . . . . . . . . . . . . .         437            437
  Capital Stock Expense. . . . . . . . . . . . . . . . .          96             96

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . .    $191,327       $142,623


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,
                                                            1999            1998    
                                                                 (in thousands)
ASSETS
<S>                                                       <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $1,533,468      $1,526,869
  Transmission . . . . . . . . . . . . . . . . . . . .        341,734         339,934
  Distribution . . . . . . . . . . . . . . . . . . . .        947,759         938,283
  General. . . . . . . . . . . . . . . . . . . . . . .        131,789         130,002
  Construction Work in Progress. . . . . . . . . . . .        114,899         118,477
          Total Electric Utility Plant . . . . . . . .      3,069,649       3,053,565
  Accumulated Depreciation . . . . . . . . . . . . . .      1,155,909       1,134,348

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      1,913,740       1,919,217



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         79,670          73,088



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         14,728           7,206
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         85,674          89,522
    Affiliated Companies . . . . . . . . . . . . . . .         24,514          17,966
    Miscellaneous. . . . . . . . . . . . . . . . . . .         11,440          11,989
    Allowance for Uncollectible Accounts . . . . . . .         (2,993)         (2,598)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         22,604          22,140
  Materials and Supplies . . . . . . . . . . . . . . .         31,183          33,263
  Accrued Utility Revenues . . . . . . . . . . . . . .         35,643          40,127
  Energy Marketing and Trading Contracts . . . . . . .         79,987          12,670
  Prepayments. . . . . . . . . . . . . . . . . . . . .         38,312          29,084

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        341,092         261,369



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        346,940         353,369


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         56,185          74,647


            TOTAL. . . . . . . . . . . . . . . . . . .     $2,737,627      $2,681,690


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,
                                                          1999              1998    
                                                                (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. . . . . . . . . . . . . . . . . . .      572,587           572,492
  Retained Earnings. . . . . . . . . . . . . . . . . .      191,327           186,441
          Total Common Shareholder's Equity. . . . . .      804,940           799,959
  Cumulative Preferred Stock - Subject to
    Mandatory Redemption . . . . . . . . . . . . . . .       25,000            25,000
  Long-term Debt . . . . . . . . . . . . . . . . . . .      959,922           959,786

          TOTAL CAPITALIZATION . . . . . . . . . . . .    1,789,862         1,784,745


OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .       43,866            42,176


CURRENT LIABILITIES:
  Short-term Debt. . . . . . . . . . . . . . . . . . .       45,700            52,500
  Accounts Payable - General . . . . . . . . . . . . .       23,416            34,631
  Accounts Payable - Affiliated Companies. . . . . . .       41,148            37,132
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .      127,913           141,831
  Interest Accrued . . . . . . . . . . . . . . . . . .       24,294            14,355
  Energy Marketing and Trading Contracts . . . . . . .       80,429            13,682
  Other. . . . . . . . . . . . . . . . . . . . . . . .       33,053            37,197

          TOTAL CURRENT LIABILITIES. . . . . . . . . .      375,953           331,328

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      438,645           442,100

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       47,842            48,710

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       41,459            32,631

CONTINGENCIES (Note 3)

            TOTAL. . . . . . . . . . . . . . . . . . .   $2,737,627        $2,681,690

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,      
                                                                1999          1998
                                                                  (in thousands)
<S>                                                           <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 27,418      $ 25,645
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . . .    23,232        22,907
    Deferred Federal Income Taxes. . . . . . . . . . . . . .       (48)        1,481
    Deferred Investment Tax Credits. . . . . . . . . . . . .      (868)         (888)
    Deferred Fuel Costs (net). . . . . . . . . . . . . . . .       836          (522)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (1,756)      (35,821)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     1,616        (2,455)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     4,484         4,439
    Prepayments. . . . . . . . . . . . . . . . . . . . . . .    (9,228)       (3,683)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (7,199)       34,627
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .   (13,918)      (15,181)
    Interest Accrued . . . . . . . . . . . . . . . . . . . .     9,939        11,857
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .    18,912         7,568
        Net Cash Flows From Operating Activities . . . . . .    53,420        49,974

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (16,908)      (22,113)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .       246         2,129
        Net Cash Flows Used For Investing Activities . . . .   (16,662)      (19,984)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .      -           51,552
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (6,800)       (6,550)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .      -          (57,000)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (21,999)      (20,661)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .      (437)         (437)
        Net Cash Flows Used For Financing Activities . . . .   (29,236)      (33,096)

Net Increase (Decrease) in Cash and Cash Equivalents . . . .     7,522        (3,106)
Cash and Cash Equivalents at Beginning of Period . . . . . .     7,206        12,626
Cash and Cash Equivalents at End of Period . . . . . . . . .  $ 14,728      $  9,520

Supplemental Disclosure:
  Cash paid for interest net of capitalized  amounts was $8,115,000 and $6,744,000 and
  for income taxes was $44,000 and $129,000 in 1999 and 1998, respectively.   Noncash
  acquisitions  under capital leases were $2,182,000 and $3,378,000 in 1999 and 1998,
  respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>                             
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                             MARCH 31, 1999                
                              (UNAUDITED)

1.   GENERAL

          The accompanying unaudited consolidated financial statements
     should be read in conjunction with the 1998 Annual Report as
     incorporated in and filed with the Form 10-K.  Certain prior-period
     amounts have been reclassified to conform with 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.   NEW ACCOUNTING STANDARDS

          In the first quarter of 1999 the Company adopted the Financial
     Accounting Standards Board's Emerging Issues Task Force Consensus
     (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
     and Risk Management Activities". The EITF requires that all energy
     trading contracts be marked-to-market.  The effect on the
     Consolidated Statements of Income of marking open trading contracts
     to market is deferred as regulatory assets or liabilities for those
     open trading transactions that are included in cost of service on
     a settlement basis for ratemaking purposes.  The adoption of the
     EITF did not have a material effect on results of operations, cash
     flows or financial condition.

3.   CONTINGENCIES

          As discussed in Note 3, of the Notes to Consolidated Financial
     Statements in the 1998 Annual Report, the deductibility of certain
     interest deductions related to American Electric Power's corporate
     owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through
     March 31, 1999 would reduce earnings by approximately $43 million
     (including interest).  The Company has made no provision for any
     possible earnings impact from this matter. 

          In 1998 the Company made payments of taxes and interest
     attributable to COLI interest deductions for taxable years 1991-1997
     to avoid the potential assessment by the IRS of any additional above
     market rate interest on the contested amount. These payments to the
     IRS are included on the Consolidated Balance Sheets in other
     property and investments pending the resolution of this matter.  The
     Company will seek refund, either administratively or through
     litigation, of all amounts paid plus interest.

          In order to resolve this issue, the Company filed suit against
     the United States in the US District Court for the Southern District
     of Ohio in March 1998.  Management believes that it has a
     meritorious position and will vigorously pursue this lawsuit.  In
     the event the resolution of this matter is unfavorable, it will have
     a material adverse impact on results of operations.

          The Company continues to be involved in certain other matters
     discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
           COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
       MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

               FIRST QUARTER 1999 vs. FIRST QUARTER 1998

     Net income increased $1.8 million or 7% in the first quarter due
primarily to increased retail sales.
     Income statement line items which changed significantly were:

                                                 Increase     
                                            (in millions)    %

     Operating Revenues . . . . . . . . . . .    $12.7         5
     Purchased Power Expense. . . . . . . . .      7.4        15
     Federal Income Taxes . . . . . . . . . .      3.1        21

     Operating revenues from retail customers increased $12.4 million
reflecting increased sales to residential and commercial customers of
13% and 5%, respectively.  Colder winter weather and customer growth
were the main reasons for the increased sales.
     The increase in purchased power expense is primarily due to
increased capacity charges from the American Electric Power (AEP) System
Power Pool (AEP Power Pool).  Under the terms of the AEP Power Pool,
capacity credits and charges are designed to allocate the cost of the
AEP System's capacity among the AEP Power Pool members based on their
relative peak demands and generating reserves.  The increase in capacity
charges can be attributed to an increase in the Company's prior twelve
month peak demand relative to the total peak demand of all AEP Power
Pool members.
     Federal income taxes attributable to operations increased primarily
due to an increase in pre-tax operating income and changes in certain
book/tax differences accounted for on a flow-through basis for rate-making
purposes.
<PAGE>
<PAGE>
<TABLE>
            INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF INCOME
                              (UNAUDITED)

<CAPTION>
                                                              Three Months Ended
                                                                   March 31,        
                                                             1999             1998
                                                                 (in thousands)
<S>                                                        <C>              <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $334,113         $328,468

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . .   41,800           44,879
  Purchased Power. . . . . . . . . . . . . . . . . . . . .   62,315           58,159
  Other Operation. . . . . . . . . . . . . . . . . . . . .   91,575           76,433
  Maintenance. . . . . . . . . . . . . . . . . . . . . . .   31,202           27,078
  Depreciation and Amortization. . . . . . . . . . . . . .   36,985           35,793
  Taxes Other Than Federal Income Taxes. . . . . . . . . .   19,029           18,697
  Federal Income Taxes . . . . . . . . . . . . . . . . . .   12,369           18,366
          TOTAL OPERATING EXPENSES . . . . . . . . . . . .  295,275          279,405
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . .   38,838           49,063
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . .    1,735            1,315
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . .   40,573           50,378
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . .   20,503           16,634
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .   20,070           33,744
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . .    1,214            1,217
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 18,856         $ 32,527

                                                               

             CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)

                                                              Three Months Ended
                                                                   March 31,        
                                                             1999             1998
                                                                 (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $253,154         $278,814
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . .   20,070           33,744

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . . . . . . . . . .   28,664           29,366
    Cumulative Preferred Stock . . . . . . . . . . . . . .    1,182            1,184
  Capital Stock Expense. . . . . . . . . . . . . . . . . .       32               33

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $243,346         $281,975

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,
                                                            1999            1998    
                                                                 (in thousands)

ASSETS
<S>                                                       <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,580,567      $2,565,041
  Transmission . . . . . . . . . . . . . . . . . . . .        917,008         913,495
  Distribution . . . . . . . . . . . . . . . . . . . .        773,187         768,888
  General (including nuclear fuel) . . . . . . . . . .        227,347         228,013
  Construction Work in Progress. . . . . . . . . . . .        161,984         156,411
          Total Electric Utility Plant . . . . . . . .      4,660,093       4,631,848
  Accumulated Depreciation and Amortization. . . . . .      2,113,688       2,081,355

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,546,405       2,550,493



NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
  DISPOSAL TRUST FUNDS . . . . . . . . . . . . . . . .        672,940         648,307



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        207,609         197,368



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         26,851          12,465
  Accounts Receivable (net). . . . . . . . . . . . . .        124,769         130,746
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         30,482          20,857
  Materials and Supplies . . . . . . . . . . . . . . .         83,538          78,009
  Accrued Utility Revenues . . . . . . . . . . . . . .         28,183          37,277
  Energy and Marketing Trading Contracts . . . . . . .         87,354          14,105
  Prepayments. . . . . . . . . . . . . . . . . . . . .          8,572           4,848

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        389,749         298,307




REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        493,496         421,475



DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         40,737          32,573



            TOTAL. . . . . . . . . . . . . . . . . . .     $4,350,936      $4,148,523

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,
                                                            1999              1998    
                                                                 (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. . . . . . . . . . . . . . . . . . .      732,639           732,605
  Retained Earnings. . . . . . . . . . . . . . . . . .      243,346           253,154
          Total Common Shareholder's Equity. . . . . .    1,032,569         1,042,343
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .        9,266             9,273
    Subject to Mandatory Redemption. . . . . . . . . .       68,445            68,445
  Long-term Debt . . . . . . . . . . . . . . . . . . .    1,030,093         1,140,789

          TOTAL CAPITALIZATION . . . . . . . . . . . .    2,140,373         2,260,850

OTHER NONCURRENT LIABILITIES:
  Nuclear Decommissioning. . . . . . . . . . . . . . .      468,181           445,934
  Other. . . . . . . . . . . . . . . . . . . . . . . .      243,836           240,320

          TOTAL OTHER NONCURRENT LIABILITIES . . . . .      712,017           686,254

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .      148,000            35,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .      110,295           108,700
  Accounts Payable - General . . . . . . . . . . . . .       67,724            53,187
  Accounts Payable - Affiliated Companies. . . . . . .       28,335            37,647
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       49,702            35,161
  Interest Accrued . . . . . . . . . . . . . . . . . .       16,537            15,279
  Rent Accrued - Rockport Plant Unit 2 . . . . . . . .       23,427             4,963
  Revenue Refunds Accrued . . . . . . . . . . . . . .       55,000              -
  Obligations Under Capital Leases . . . . . . . . . .       10,681             9,667
  Energy and Marketing Trading Contracts . . . . . . .       87,838            15,228
  Other. . . . . . . . . . . . . . . . . . . . . . . .       77,234            67,102

          TOTAL CURRENT LIABILITIES. . . . . . . . . .      674,773           381,934

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      560,136           559,288

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .      127,881           129,779

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .       87,785            88,712

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       47,971            41,706

CONTINGENCIES (Note 4)

            TOTAL. . . . . . . . . . . . . . . . . . .   $4,350,936        $4,148,523

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,       
                                                               1999           1998
                                                                 (in thousands)
<S>                                                          <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 20,070       $ 33,744
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .   37,995         36,889
    Amortization of Incremental Nuclear
      Refueling Outage Expenses (net). . . . . . . . . . . .    2,347          4,777
    Unrecovered Fuel and Purchased Power Costs . . . . . . .  (52,664)       (22,203)
    Deferred Nuclear Outage Costs (net). . . . . . . . . . .  (30,000)          -
    Deferred Federal Income Taxes. . . . . . . . . . . . . .    5,365          6,494
    Deferred Investment Tax Credits. . . . . . . . . . . . .   (1,898)        (1,909)
    Deferred Property Taxes. . . . . . . . . . . . . . . . .   (9,325)        (8,185)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    5,977             96
    Fuel, Materials and Supplies . . . . . . . . . . . . . .  (15,154)        (5,839)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .    9,094           (964)
    Prepayments. . . . . . . . . . . . . . . . . . . . . . .   (3,724)        (1,223)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    5,225         10,571
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .   14,541         17,551
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .   18,464         18,464
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . .   55,000           -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .   10,540        (18,242)
        Net Cash Flows From Operating Activities . . . . . .   71,853         70,021

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .  (30,114)       (25,290)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .      903            698
        Net Cash Flows Used For Investing Activities . . . .  (29,211)       (24,592)

FINANCING ACTIVITIES:
  Change in Short-term Debt (net). . . . . . . . . . . . . .    1,595         (9,125)
  Retirement of Cumulative Preferred Stock . . . . . . . . .       (5)          -   

  Dividends Paid on Common Stock . . . . . . . . . . . . . .  (28,664)       (29,366)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .   (1,182)        (1,184)
        Net Cash Flows Used For Financing Activities . . . .  (28,256)       (39,675)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .   14,386          5,754
Cash and Cash Equivalents at Beginning of Period . . . . . .   12,465          5,860
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 26,851       $ 11,614

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts  was $18,527,000 and $14,412,000,
  respectively and for income taxes was $125,000 in 1998.  Noncash acquisitions under
  capital leases were $3,783,000 and $16,630,000 in 1999 and 1998, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
            INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                             MARCH 31, 1999                
                              (UNAUDITED)

1. GENERAL

      The accompanying unaudited consolidated financial statements
   should be read in conjunction with the 1998 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 April 1999 the Company called $65 million of first mortgage
   bonds, $20 million of 6.80% series due 2003, $20 million of 6.55%
   series due 2003 and $25 million of 6.55% series due 2004, for early
   redemption in May.  Consequently, the bonds were reclassified as a
   current liability on the Consolidated Balance Sheets.

3. NEW ACCOUNTING STANDARDS

      In the first quarter of 1999 the Company adopted the Financial
   Accounting Standards Board's Emerging Issues Task Force Consensus
   (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
   and Risk Management Activities". The EITF requires that all energy
   trading contracts be marked-to-market.  The effect on the
   Consolidated Statements of Income of marking open trading contracts
   to market is deferred as regulatory assets or liabilities for those
   open trading transactions that are included in cost of service on a
   settlement basis for ratemaking purposes.  The adoption of the EITF
   did not have a material effect on results of operations, cash flows
   or financial condition.

4. CONTINGENCIES

   Litigation

      As discussed in Note 3, of the Notes to Consolidated Financial
   Statements in the 1998 Annual Report, the deductibility of certain
   interest deductions related to American Electric Power's corporate
   owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through March
   31, 1999 would reduce earnings by approximately $66 million
   (including interest).  The Company has made no provision for any
   possible earnings impact from this matter. 
<PAGE>
      In 1998 the Company made payments of taxes and interest
   attributable to COLI interest deductions for taxable years 1991-1997
   to avoid the potential assessment by the IRS of any additional above
   market rate interest on the contested amount. These payments to the
   IRS are included on the Consolidated Balance Sheets in other property
   and investments pending the resolution of this matter.  The Company
   will seek refund, either administratively or through litigation, of
   all amounts paid plus interest.

      In order to resolve this issue, the Company filed suit against
   the United States in the US District Court for the Southern District
   of Ohio in March 1998.  Management believes that it has a meritorious
   position and will vigorously pursue this lawsuit.  In the event the
   resolution of this matter is unfavorable, it will have a material
   adverse impact on results of operations.

   Cook Plant Shutdown

      As discussed in Note 3 of the Notes to Consolidated Financial
   Statements in the 1998 Annual Report, both units of the Cook Plant
   were 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 NRC issued a Confirmatory Action Letter in September 1997
   requiring the Company to address certain issues identified in the
   letter.  During 1998 the NRC notified the Company that it had
   convened a Restart Panel for Cook Plant and provided a list of
   required restart activities.  In order to identify and resolve all
   issues, including those in the letter, necessary to restart the Cook
   units, the Company is working with the NRC and will be meeting with
   the Panel on a regular basis, until the units are returned to
   service.

      In January 1999 the Company announced that additional engineering
   reviews will be conducted at the Cook Plant delaying the restart of
   the units.  Previously, the units were scheduled to return to service
   at the end of the first and second quarters of 1999.  The decision
   to delay restart resulted from internal assessments that indicated
   a need to conduct expanded system readiness reviews.  A new restart
   schedule will be developed based on the results of the expanded
   reviews and should be available in June 1999.  When maintenance and
   other activities required for restart are complete, the Company will
   seek concurrence from the NRC to return the Cook Plant to service. 
   Until these additional reviews are completed, management is unable
   to determine when the units will be returned to service.

      In May 1999 the Company received a letter from the NRC indicating
   that NRC senior managers had identified Cook Plant as an "agency-focus
   plant."  The senior managers concluded that continued agency-level 
   oversight was appropriate; however, the NRC required no
   additional action to redirect Cook Plant activities.  The letter
   states that the NRC staff will continue to monitor Cook Plant
   performance through the Restart Panel process and evaluate whether
   additional action may be necessary.

      The cost of electricity supplied to retail customers remained
   higher due to the outage of the two Cook Plant nuclear units since
   higher cost coal-fired generation and coal based purchased power
   continue to be substituted for low cost nuclear generation.  The
   Indiana and Michigan retail jurisdictional fuel cost recovery
   mechanisms permit the recovery, subject to regulatory commission
   review and approval, of changes in fuel costs including the fuel
   component of purchased power in the Indiana jurisdiction and changes
   in replacement power in the Michigan jurisdiction.  Under these fuel
   cost recovery mechanisms, retail rates contain a fuel cost adjustment
   factor that reflects estimated fuel costs for the period during which
   the factor will be in effect subject to reconciliation to actual fuel
   costs in a future proceeding.  When actual fuel costs exceed the
   estimated costs reflected in the billing factor a regulatory asset
   is recorded and revenues are accrued.  Therefore, a regulatory asset
   has been recorded and revenues accrued in anticipation of the future
   reconciliation and billing under the fuel cost recovery mechanisms
   of the higher fuel costs to replace Cook energy during the extended
   outage.  At March 31, 1999, the regulatory asset was $118 million.

      On March 30, 1999 the Indiana Utility Regulatory Commission
   (IURC) approved a settlement agreement that resolves all matters
   related to the reasonableness of fuel costs and all outage issues
   during the extended outage of the Cook Plant.  The settlement
   agreement provides for, among other things, a credit of $55 million,
   including interest, to Indiana retail customers; authorization to
   defer any unrecovered fuel revenues accrued between September 9, 1997
   and December 31, 1999, including the $52.3 million revenue portion
   of the $55 million credit; authorization to defer up to $150 million
   of incremental operation and maintenance costs for the Cook Plant
   above the amount included in base rates; amortization of the fuel
   recoveries and non-fuel operation and maintenance cost deferrals over
   a five-year period ending December 31, 2003; a freeze in base rates
   through December 31, 2003; and a fixed fuel recovery charge through
   March 1, 2004.  The $55 million credit will be refunded through
   customers' bills  during the months of July, August and September
   1999.

      The incremental costs incurred in first quarter 1999 for restart
   of the Cook units were $45 million of which $30 million were deferred
   pursuant to the settlement agreement discussed above.

      Unless the costs of the extended outage and restart efforts are
   recovered from customers, there would be a material adverse effect
   on results of operations, cash flows, and possibly financial
   condition.

   Other

      The Company continues to be involved in other matters discussed
   in its 1998 Annual Report.

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

               FIRST QUARTER 1999 vs. FIRST QUARTER 1998

RESULTS OF OPERATIONS
   Although operating revenues increased $5.6 million or 2%, net income
decreased $13.7 million or 41% due to increased operation and
maintenance expense related to an extended outage of the Cook Nuclear
Plant which was shut down in September 1997.
   Income statement line items which changed significantly were:

                                              Increase (Decrease)
                                              (in millions)   %

   Operating Revenues. . . . . . . . . . . .     $ 5.6        2
   Fuel Expense. . . . . . . . . . . . . . .      (3.1)      (7)
   Purchased Power Expense . . . . . . . . .       4.2        7
   Other Operation Expense . . . . . . . . .      15.1       20
   Maintenance Expense . . . . . . . . . . .       4.1       15
   Federal Income Taxes. . . . . . . . . . .      (6.0)     (33)
   Interest Charges. . . . . . . . . . . . .       3.9       23

   Operating revenues increased due to increased capacity credits from
the American Electric Power (AEP) System Power Pool (AEP Power Pool) and
an increase in transmission and business development revenues.  Under
the terms of the AEP Power Pool, capacity credits and charges are
designed to allocate the cost of the AEP System's capacity among the AEP
Power Pool members based on their relative peak demands and generating
reserves.  The increase in capacity credits received can be attributed
to a decrease in the Company's prior twelve month peak demand relative
to the total peak demand of all Power Pool members.
   Fuel expense decreased as a result of a decline in generation
reflecting reduced availability of coal-fired generation due to outages
in the first quarter of 1999.
   The increase in purchased power expense resulted from increased
purchases from the AEP Power Pool to replace power that would have been
generated by the coal fired units which were unavailable.
   Other operation expense increased due to increased nuclear operation
expenses for engineering costs incurred as a result of the extended
shutdown.  The extended shutdown of the Cook Plant also accounted for
the increase in maintenance expense.
   Federal income taxes attributable to operations decreased due to a
decrease in pre-tax operating income.
   Interest charges increased due to an accrual of interest for revenue
refunds ordered by the Indiana commission as part of a settlement
agreement and due to higher outstanding balances of long-term debt.
FINANCIAL CONDITION
   Total plant and property additions including capital leases for the
period were $34 million.  During the first three months of 1999 short-term
debt outstanding increased by $2 million.
   In April 1999 the Company called $65 million of first mortgage bonds,
$20 million of 6.80% series due 2003, $20 million of 6.55% series due
2003 and $25 million of 6.55% series due 2004, for early redemption in
May.  Consequently, the bonds were reclassified as a current liability
on the Consolidated Balance Sheets.
OTHER MATTERS
Spent Nuclear Fuel (SNF) Litigation
   As discussed in Management's Discussion and Analysis of Results of
Operations and Financial Condition (MDA) in the 1998 Annual Report, as
a result of the Department of Energy's (DOE) failure to make sufficient
progress toward a permanent repository or otherwise assume
responsibility for SNF, the Company along with a number of unaffiliated
utilities and states filed suit in the United States (US) Court of
Appeals for the District of Columbia Circuit requesting, among other
things, that the court order DOE to meet its obligations under the law. 
The court ordered the parties to proceed with contractual remedies but
declined to order DOE to begin accepting SNF for disposal.  DOE
estimates its planned site for the nuclear waste will not be ready until
2010.  In June 1998, the Company filed a complaint in the US Court of
Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual deadline
to begin disposing of SNF generated by the Cook Plant.  Similar lawsuits
have been filed by other utilities.  On April 6, 1999, the court granted
DOE's motion to dismiss a lawsuit filed by another utility.  I&M's case
has been suspended pending final resolution of the other utility's case.
<PAGE>
Cook Nuclear Plant Shutdown
   As discussed in MDA in the 1998 Annual Report, management shut down
both units of the Cook Plant in September 1997 due to questions, which
arose during a Nuclear Regulatory Commission (NRC) architect engineer
design inspection, regarding the operability of certain safety systems. 
The NRC issued a Confirmatory Action Letter in September 1997 requiring
the Company to address certain issues identified in the letter.  During
1998 the NRC notified the Company that it had convened a Restart Panel
for Cook Plant and provided a list of required restart activities.  In
order to identify and resolve all issues, including those in the letter,
necessary to restart the Cook units, the Company is working with the NRC
and will be meeting with the Panel on a regular basis, until the units
are returned to service.
   In January 1999 the Company announced that additional engineering
reviews will be conducted at the Cook Plant delaying the restart of the
units.  Previously, the units were scheduled to return to service at the
end of the first and second quarters of 1999.  The decision to delay
restart resulted from internal assessments that indicated a need to
conduct expanded system readiness reviews.  A new restart schedule will
be developed based on the results of the expanded reviews and should be
available in June 1999.  When maintenance and other activities required
for restart are complete, the Company will seek concurrence from the NRC
to return the Cook Plant to service.  Until these additional reviews are
completed, management is unable to determine when the units will be
returned to service.
   In May 1999 the Company received a letter from the NRC indicating
that NRC senior managers had identified Cook Plant as an "agency-focus
plant."  The senior managers concluded that continued agency-level
oversight was appropriate; however, the NRC required no additional
action to redirect Cook Plant activities.  The letter states that the
NRC staff will continue to monitor Cook Plant performance through the
Restart Panel process and evaluate whether additional action may be
necessary.
   The cost of electricity supplied to retail customers remained higher
due to the outage of the two Cook Plant nuclear units since higher cost
coal-fired generation and coal based purchased power continue to be
substituted for low cost nuclear generation.  The Indiana and Michigan
retail jurisdictional fuel cost recovery mechanisms permit the recovery,
subject to regulatory commission review and approval, of changes in fuel
costs including the fuel component of purchased power in the Indiana
jurisdiction and changes in replacement power in the Michigan
jurisdiction.  Under these fuel cost recovery mechanisms, retail rates
contain a fuel cost adjustment factor that reflects estimated fuel costs
for the period during which the factor will be in effect subject to
reconciliation to actual fuel costs in a future proceeding.  When actual
fuel costs exceed the estimated costs reflected in the billing factor
a regulatory asset is recorded and revenues are accrued.  Therefore, a
regulatory asset has been recorded and revenues accrued in anticipation
of the future reconciliation and billing under the fuel cost recovery
mechanisms of the higher fuel costs to replace Cook energy during the
extended outage.  At March 31, 1999, the regulatory asset was $118
million.
   On March 30, 1999 the Indiana Utility Regulatory Commission (IURC)
approved a settlement agreement that resolves all matters related to the
reasonableness of fuel costs and all outage issues during the extended
outage of the Cook Plant.  The settlement agreement provides for, among
other things, a credit of $55 million, including interest, to Indiana
retail customers; authorization to defer any unrecovered fuel revenues
accrued between September 9, 1997 and December 31, 1999, including the
$52.3 million revenue portion of the $55 million credit; authorization
to defer up to $150 million of incremental operation and maintenance
costs for the Cook Plant above the amount included in base rates;
amortization of the fuel recoveries and non-fuel operation and
maintenance cost deferrals over a five-year period ending December 31,
2003; a freeze in base rates through December 31, 2003; and a fixed fuel
recovery charge through March 1, 2004.  The $55 million credit will be
refunded through customers' bills  during the months of July, August and
September 1999.
   The incremental costs incurred in first quarter 1999 for restart of
the Cook units were $45 million of which $30 million were deferred
pursuant to the settlement agreement discussed above.
   Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect on
results of operations, cash flows, and possibly financial condition.
Market Risks
   The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and interest
rates.  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, 1998.  Market risk represents the risk of
loss that may impact the Company due to adverse changes in commodity
market prices and interest rates.
   The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at March 31, 1999 is not materially
different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
   On or about midnight on December 31, 1999, digital computing systems
may begin to produce erroneous results or fail, unless these systems are
modified or replaced, because such systems may be programmed incorrectly
and interpret the date of January 1, 2000 as being January 1st of the
year 1900 or another incorrect date.  In addition, certain systems may
fail to detect that the year 2000 is a leap year.  Problems can also
arise earlier than January 1, 2000, as dates in the next millennium are
entered into non-Y2K ready programs.

Readiness Program - Internally, the Company, through the AEP System, is
modifying or replacing its computer hardware and software programs to
minimize Y2K-related failures and repair such failures if they occur. 
This includes both information technology (IT) systems, which are
mainframe and client server applications, and embedded logic (non-IT)
systems, such as process controls for energy production and delivery. 
Externally, the problem is being addressed with entities that interact
with the Company, including suppliers, customers, creditors, financial
service organizations and other parties essential to the Company's
operations.  In the course of the external evaluation, the Company has
sought written assurances from third parties regarding their state of
Y2K readiness.

   Another issue we are addressing is the impact of electric power grid
problems that may occur outside of our transmission system.  The
Company, along with other electric utilities in North America, regularly
submits information to the North American Electric Reliability Council
(NERC) as part of NERC's Y2K readiness program.  NERC then publicly
reports summary information to the US DOE regarding the Y2K readiness
of electric utilities.  AEP participated in an industry-wide
NERC-sponsored drill on April 9, 1999 simulating the partial loss of
voice and data communications.  There were no major problems encountered
with relaying information with the use of backup telecommunications
systems.  AEP and other utilities plan to participate in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999, to
prepare for operations under Y2K conditions.
   The NERC report, dated April 30, 1999 and entitled: Preparing the
Electric Power Systems of North America for Transition to the Year 2000
- A Status Report and Work Plan, First Quarter 1999, states that: "With
more than 75% of mission critical components tested through March 31,
1999, findings in the field continue to indicate that the transition
through critical Y2K dates is expected to have minimal impact on
electric system operations in North America."  The report also indicates
that, "the risk of electrical outages by Y2K appears to be no higher
than the risks we already experience" from incidents such as severe
wind, ice, floods, equipment failures and power shortages during an
extremely hot or cold period.
   Through the Electric Power Research Institute, an electric utility
industry-wide effort has been established to deal with Y2K problems
affecting embedded systems.  Under this effort, participating utilities
are working together to assess specific vendors' system problems and
test plans.
   The state regulatory commissions in the Company's service territory
are also reviewing the Y2K readiness of the Company.

Company's State of Readiness - Work has been prioritized in accordance
with business risk.  The highest priority has been assigned to
activities that potentially affect safety, the physical generation and
delivery of energy, and communications; followed by back office
activities such as customer service/billing, regulatory reporting,
internal reporting and administrative activities (e.g., payroll,
procurement, accounts payable); and finally, those activities that would
cause inconvenience or productivity loss in normal business operations.
   The following chart shows our progress toward becoming ready for the
Y2K as of March 31, 1999:
                                 IT SYSTEMS              NON-IT  SYSTEMS
                         COMPLETION                 COMPLETION
                         DATE/ESTIMATED   PERCENT   DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of      2/24/1998        100%      5/31/1998       100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment: 
Identifying all Company    7/31/1998        100%       2/15/1999     100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.

Remediation/Testing: The
process of modifying,      6/30/1999     Mainframe:    6/30/1999*     65%
replacing or retiring                    94%
those mission critical and                       
high priority digital-based
systems with problems                    Client
processing dates in the                  Server:
Year 2000. Testing these                 56%
systems to ensure that after             
modifications have been                  
implemented correct date                 
processing occurs and full
functionality has been maintained.

*The Company is upgrading its 800 MHZ trunked radio system, a mission 
critical non-IT system, for Y2K readiness and it is anticipated that the 
upgrade should be complete by September 30, 1999.

The Company continues to make steady progress toward the June 30, 1999 
target date andanticipates completing the remediation/testing work for mission
critical and high-priority systems by the June 30, 1999 target date except as
noted in the table.<PAGE>
Costs to Address the Company's Year 2000 Issues - Through
March 31, 1999, the Company has spent $5 million on the Year 2000 project 
and, estimates spending an additional $5 million to $7 million to achieve 
Y2K readiness.  Most Y2K costs are for software modifications, IT 
consultants and salaries and are expensed; however, in certain cases
the Company has acquired hardware that was capitalized.  The Company intends 
to fund these expenditures through internal sources.  Although significant, 
the cost of becoming Y2K compliant is not expected to have a material impact
on the Company's results of operations, cash flows or financial condition.

Risks of the Company's Y2K Issues - The applications posing the greatest 
business risk to the Company's operations should they experience Y2K problems
are:
   Automated power generation, transmission and distribution systems
   Telecommunications systems
   Energy trading systems
   Time-in-use, demand and remote metering systems for commercial and
   industrial customers and
   Work management and billing systems.
   The potential problems related to erroneous processing by, or failure of, 
   these systems are:
   Power service interruptions to customers
   Interrupted revenue data gathering and collection
   Poor customer relations resulting from delayed billing and
   settlement.
   Although it is difficult to hypothesize a most reasonably likely worst case
   Y2K scenario with any degree of certainty, management believes that such 
   a scenario would be small, localized interruptions of service, which 
   would be restored.
   In addition, although relationships with third parties, such as suppliers,
customers and other electric utilities, are being monitored, these third parties
nonetheless represent a risk that cannot be assessed with precision or 
controlled with certainty.
<PAGE>
   Due to the complexity of the problem and the interdependent nature of 
computer systems, if our corrective actions, and/or the actions of others 
who impact the AEP System's operations but are not affiliated with the AEP 
System, fail for critical applications, Y2K-related issues may materially 
adversely affect the Company.

Company's Contingency Plans - To address possible failures of electric 
generation and delivery of electrical energy due to Y2K related failures, we
have established a draft Y2K contingency plan and submitted it to the East
Central Area Reliability Council in December 1998 as part of NERC's review 
of regional and individual electric utility contingency plans in 1999.  
NERC's target date is June 1999 for the completion of this contingency plan.
In addition, the Company intends to establish contingency plans for
its business units to address alternatives if Y2K related failures occur. 
Contingency plans will be developed by the end of 1999.
   The Company's plans build upon the disaster recovery, system restoration, and
contingency planning that we have had in place and include:
   Availability of additional power generation reserves.
   Coal inventory of approximately 45 days of normal usage.
   Identifying critical operational locations, with key employees on duty 
   at those locations during the Y2K transition.

<PAGE>
<PAGE>
<TABLE>
                        KENTUCKY POWER COMPANY
                         STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                        Three Months Ended
                                                             March 31,       
                                                        1999           1998 
                                                           (in thousands)
<S>                                                   <C>            <C> 
OPERATING REVENUES . . . . . . . . . . . . . . . . .  $90,741        $87,345

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . . . . . . .   19,691         22,301
  Purchased Power. . . . . . . . . . . . . . . . . .   24,427         21,211
  Other Operation. . . . . . . . . . . . . . . . . .   12,351         10,994
  Maintenance. . . . . . . . . . . . . . . . . . . .    4,791          9,166
  Depreciation and Amortization. . . . . . . . . . .    7,190          6,910
  Taxes Other Than Federal Income Taxes. . . . . . .    2,534          2,492
  Federal Income Taxes . . . . . . . . . . . . . . .    4,397          2,180

          TOTAL OPERATING EXPENSES . . . . . . . . .   75,381         75,254

OPERATING INCOME . . . . . . . . . . . . . . . . . .   15,360         12,091

NONOPERATING LOSS. . . . . . . . . . . . . . . . . .     (114)           (71)

INCOME BEFORE INTEREST CHARGES . . . . . . . . . . .   15,246         12,020

INTEREST CHARGES . . . . . . . . . . . . . . . . . .    7,037          7,003

NET INCOME . . . . . . . . . . . . . . . . . . . . .  $ 8,209        $ 5,017

                                                             

                    STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)
                                                        Three Months Ended
                                                             March 31,      
                                                        1999           1998 
                                                           (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . .  $71,452        $78,076

NET INCOME . . . . . . . . . . . . . . . . . . . . .    8,209          5,017

CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . .    7,443          7,075

BALANCE AT END OF PERIOD . . . . . . . . . . . . . .  $72,218        $76,018

                    

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,
                                                      1999            1998    
                                                         (in thousands)
ASSETS
<S>                                               <C>             <C> 
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . .    $  267,282      $  267,201
  Transmission . . . . . . . . . . . . . . . .       327,989         326,989
  Distribution . . . . . . . . . . . . . . . .       353,918         351,407
  General. . . . . . . . . . . . . . . . . . .        68,259          68,038
  Construction Work in Progress. . . . . . . .        31,954          30,076
          Total Electric Utility Plant . . . .     1,049,402       1,043,711
  Accumulated Depreciation and Amortization. .       322,483         315,546

          NET ELECTRIC UTILITY PLANT . . . . .       726,919         728,165


OTHER PROPERTY AND INVESTMENTS . . . . . . . .        15,126          12,078


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . .         4,251           1,935
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . .        22,919          23,295
    Affiliated Companies . . . . . . . . . . .         6,084           8,797
    Miscellaneous. . . . . . . . . . . . . . .         3,151           4,019
    Allowance for Uncollectible Accounts . . .          (930)           (848)
  Fuel . . . . . . . . . . . . . . . . . . . .         9,895           7,888
  Materials and Supplies . . . . . . . . . . .        13,538          13,652
  Accrued Utility Revenues . . . . . . . . . .        13,573          13,560
  Energy Marketing and Trading Contracts . . .        32,257           4,726
  Prepayments. . . . . . . . . . . . . . . . .         1,339           1,657

          TOTAL CURRENT ASSETS . . . . . . . .       106,077          78,681


REGULATORY ASSETS. . . . . . . . . . . . . . .        91,785          92,447


DEFERRED CHARGES . . . . . . . . . . . . . . .         8,684          10,476


            TOTAL. . . . . . . . . . . . . . .    $  948,591      $  921,847


See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>                 KENTUCKY POWER COMPANY
                            BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                   March 31,     December 31,
                                                     1999            1998    
                                                        (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. . . . . . . . . . . . . . .     148,750          148,750
  Retained Earnings. . . . . . . . . . . . . .      72,218           71,452
          Total Common Shareholder's Equity. .     271,418          270,652
  Long-term Debt . . . . . . . . . . . . . . .     296,089          308,838

          TOTAL CAPITALIZATION . . . . . . . .     567,507          579,490

OTHER NONCURRENT LIABILITIES . . . . . . . . .      26,124           26,827

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . .      72,797           60,000
  Short-term Debt. . . . . . . . . . . . . . .      11,950           20,350
  Accounts Payable - General . . . . . . . . .       9,919           12,917
  Accounts Payable - Affiliated Companies. . .      13,270           11,814
  Customer Deposits. . . . . . . . . . . . . .       3,961            4,038
  Taxes Accrued. . . . . . . . . . . . . . . .      12,387            7,256
  Interest Accrued . . . . . . . . . . . . . .       8,795            6,241
  Energy Marketing and Trading Contracts . . .      32,431            5,089
  Other. . . . . . . . . . . . . . . . . . . .      12,505           13,612

          TOTAL CURRENT LIABILITIES. . . . . .     178,015          141,317

DEFERRED INCOME TAXES. . . . . . . . . . . . .     158,415          158,706

DEFERRED INVESTMENT TAX CREDITS. . . . . . . .      13,900           14,200

DEFERRED CREDITS . . . . . . . . . . . . . . .       4,630            1,307

CONTINGENCIES (Note 4)

            TOTAL. . . . . . . . . . . . . . .    $948,591         $921,847


See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                        KENTUCKY POWER COMPANY
                       STATEMENTS OF CASH FLOWS
                              (UNAUDITED)
<CAPTION>
                                                         Three Months Ended
                                                              March 31,      
                                                        1999            1998
                                                           (in thousands)
<S>                                                   <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . .  $  8,209       $  5,017
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . .     7,192          6,913
    Deferred Federal Income Taxes. . . . . . . . . .      (254)            32
    Deferred Investment Tax Credits. . . . . . . . .      (300)          (305)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . .     4,039         (5,100)
    Fuel, Materials and Supplies . . . . . . . . . .    (1,893)           542
    Accrued Utility Revenues . . . . . . . . . . . .       (13)         2,726 
    Accounts Payable . . . . . . . . . . . . . . . .    (1,542)        (6,221)
    Taxes Accrued. . . . . . . . . . . . . . . . . .     5,131          2,695
    Interest Accrued . . . . . . . . . . . . . . . .     2,554          1,971
  Other (net). . . . . . . . . . . . . . . . . . . .     1,519          2,192
        Net Cash Flows From Operating Activities . .    24,642         10,462

INVESTING ACTIVITIES - Construction Expenditures . .    (6,483)        (6,553)

FINANCING ACTIVITIES:
  Change in Short-term Debt (net). . . . . . . . . .    (8,400)         2,775
  Dividends Paid . . . . . . . . . . . . . . . . . .    (7,443)        (7,075)
        Net Cash Flows Used For
          Financing Activities . . . . . . . . . . .   (15,843)        (4,300)

Net Increase (Decrease) in Cash and Cash Equivalents     2,316           (391)
Cash and Cash Equivalents at Beginning of Period . .     1,935          1,381
Cash and Cash Equivalents at End of Period . . . . .  $  4,251       $    990

Supplemental Disclosure:
  Cash  paid for  interest  net of  capitalized  amounts  was $4,374,000  and
  $4,931,000  in 1999  and  1998,  respectively.  Noncash  acquisitions under
  capital leases were $568,000 and $1,568,000 in 1999 and 1998, respectively.


See Notes to Financial Statements.
/TABLE
<PAGE>
<PAGE>
                        KENTUCKY POWER COMPANY
                     NOTES TO FINANCIAL STATEMENTS
                            MARCH 31, 1999        
                              (UNAUDITED)
1. GENERAL

      The accompanying unaudited financial statements should be read in
   conjunction with the 1998 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 April 1999 the Company called $13 million of 7.90% First
   Mortgage Bonds due 2023 for early redemption in May.  Consequently,
   the bonds were reclassified as a current liability on the Balance
   Sheets.

3. NEW ACCOUNTING STANDARDS

      In the first quarter of 1999 the Company adopted the Financial
   Accounting Standards Board's Emerging Issues Task Force Consensus
   (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
   and Risk Management Activities". The EITF requires that all energy
   trading contracts be marked-to-market.  The effect on the Statements
   of Income of marking open trading contracts to market is deferred as
   regulatory assets or liabilities for those open trading transactions
   that are included in cost of service on a settlement basis for
   ratemaking purposes.  The adoption of the EITF did not have a
   material effect on results of operations, cash flows or financial
   condition.

4. CONTINGENCIES

      As discussed in Note 3, of the Notes to Financial Statements in
   the 1998 Annual Report, the deductibility of certain interest
   deductions related to American Electric Power's corporate owned life
   insurance (COLI) program for taxable years 1992-1996 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 COLI interest deductions through March 31, 1999 would
   reduce earnings by approximately $8 million (including interest). 
   The Company has made no provision for any possible earnings impact
   from this matter. 

      In 1998 the Company made payments of taxes and interest
   attributable to COLI interest deductions for taxable years 1992-1997
   to avoid the potential assessment by the IRS of any additional above
   market rate interest on the contested amount. These payments to the
   IRS are included on the Balance Sheets in other property and
   investments pending the resolution of this matter.  The Company will
   seek refund, either administratively or through litigation, of all
   amounts paid plus interest.

      In order to resolve this issue, the Company filed suit against
   the United States in the US District Court for the Southern District
   of Ohio in March 1998.  Management believes that it has a meritorious
   position and will vigorously pursue this lawsuit.  In the event the
   resolution of this matter is unfavorable, it will have a material
   adverse impact on results of operations.

      The Company continues to be involved in certain other matters
   discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
                        KENTUCKY POWER COMPANY
       MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

               FIRST QUARTER 1999 vs. FIRST QUARTER 1998

         Net income increased $3.2 million or 64% due to an increase in
sales to retail customers reflecting colder weather.
        Income statement line items which changed significantly were:
                                              Increase(Decrease)
                                              (in millions)  %

        Operating Revenues. . . . . . . . . . .      $ 3.4       4
        Fuel Expense. . . . . . . . . . . . . .       (2.6)    (12)
        Purchased Power Expense . . . . . . . .        3.2      15
        Other Operation Expense . . . . . . . .        1.4      12
        Maintenance Expense . . . . . . . . . .       (4.4)    (48)
        Federal Income Taxes. . . . . . . . . .        2.2     102

        Operating revenues increased due to a 7% increase in retail sales. 
Sales to residential and commercial customers increased 12% and 13%,
respectively, due primarily to colder winter weather.
        The decrease in fuel expense is primarily attributable to a decrease
in generation reflecting reduced availability of the Company's Big Sandy
Plant in 1999 due to forced outages.
        Purchased power expense increased primarily due to increased energy
purchases and capacity charges from the American Electric Power System
Power Pool (AEP Power Pool).  The increase in purchases from the AEP
Power Pool were required to meet increased demand for energy and to
replace power not available due to the Big Sandy Plant and an
affiliate's plant outages.  The affiliate, who is not a member of the
AEP Power Pool, has an agreement with the Company to sell a percentage
of its generation to the Company when the affiliate's generation is
available.  Under the terms of the AEP Power Pool, capacity credits and
charges are designed to allocate the cost of the AEP System's capacity
among the AEP Power Pool members based on their relative peak demands
and generating reserves.  The increase in capacity charges can be
attributed to an increase in the Company's prior twelve month peak
demand relative to the total peak demand of all AEP Power Pool members.
<PAGE>
        The increase in other operation expense is due to accrual
adjustments for employee pensions and benefits recorded in 1999 and
1998.  The 1999 adjustment was unfavorable while the 1998 adjustment was
favorable.
        The decrease in maintenance expense was primarily due to decreased
overhead distribution line maintenance expenditures resulting from
maintenance costs incurred in 1998 to repair and restore customers'
service after winter storm damage.
        An increase in pre-tax operating income was the primary cause of the
increase in federal income taxes attributable to operations.
<PAGE>
<PAGE>
<TABLE>
                  OHIO POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                                                  Three Months Ended
                                                                       March 31,     
                                                                   1999        1998
                                                                    (in thousands)
<S>                                                             <C>         <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . $518,221    $515,672 
                                                                            
OPERATING EXPENSES:                                                         
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  189,163     193,275 
  Purchased Power. . . . . . . . . . . . . . . . . . . . . . . .   21,273      19,590 
  Other Operation. . . . . . . . . . . . . . . . . . . . . . . .   85,061      80,901 
  Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . .   25,490      30,593 
  Depreciation and Amortization. . . . . . . . . . . . . . . . .   36,785      35,863 
  Taxes Other Than Federal Income Taxes. . . . . . . . . . . . .   43,853      42,658 
  Federal Income Taxes . . . . . . . . . . . . . . . . . . . . .   37,640      33,723 
          TOTAL OPERATING EXPENSES . . . . . . . . . . . . . . .  439,265     436,603 

OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . .   78,956      79,069 
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . .    2,000       1,238 
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . .   80,956      80,307 
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . .   20,135      19,871 
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . .   60,821      60,436 
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . . . .      367         370 
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . . $ 60,454    $ 60,066 

                                                               

             CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)
                                                                  Three Months Ended
                                                                       March 31,     
                                                                   1999        1998
                                                                    (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . . . $587,500    $590,151

NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . .   60,821      60,436

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . . . . . . . . . . . . .   57,703      52,775
    Cumulative Preferred Stock . . . . . . . . . . . . . . . . .      367         370

BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . . . $590,251    $597,442


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,
                                                              1999            1998   

                                                                 (in thousands)
ASSETS
<S>                                                       <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,677,630      $2,646,597
  Transmission . . . . . . . . . . . . . . . . . . . .        845,755         842,318
  Distribution . . . . . . . . . . . . . . . . . . . .        954,198         949,224
  General (including mining assets). . . . . . . . . .        680,173         689,815
  Construction Work in Progress. . . . . . . . . . . .        115,146         129,887
          Total Electric Utility Plant . . . . . . . .      5,272,902       5,257,841
  Accumulated Depreciation and Amortization. . . . . .      2,493,936       2,461,376

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,778,966       2,796,465



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        230,832         218,311



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .        114,785          89,652
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .        255,995         215,665
    Affiliated Companies . . . . . . . . . . . . . . .        118,333          63,922
    Miscellaneous. . . . . . . . . . . . . . . . . . .         41,063          28,139
    Allowance for Uncollectible Accounts . . . . . . .         (2,290)         (1,678)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .        117,956          94,914
  Materials and Supplies . . . . . . . . . . . . . . .         84,237          86,870
  Accrued Utility Revenues . . . . . . . . . . . . . .         39,419          43,501
  Energy Marketing and Trading Contracts . . . . . . .        125,927          19,790
  Prepayments. . . . . . . . . . . . . . . . . . . . .         47,536          34,523

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        942,961         675,298


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        549,597         551,776


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         88,536         102,830


            TOTAL. . . . . . . . . . . . . . . . . . .     $4,590,892      $4,344,680


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                  OHIO POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                           March 31,      December 31,
                                                             1999             1998   

                                                                (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. . . . . . . . . . . . . . . . . . .       462,338          462,335
  Retained Earnings. . . . . . . . . . . . . . . . . .       590,251          587,500
          Total Common Shareholder's Equity. . . . . .     1,373,790        1,371,036
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .        17,357           17,370
    Subject to Mandatory Redemption. . . . . . . . . .        11,850           11,850
  Long-term Debt . . . . . . . . . . . . . . . . . . .       975,452        1,073,456

          TOTAL CAPITALIZATION . . . . . . . . . . . .     2,378,449        2,473,712

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .       374,244          360,330

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .        98,958           11,472
  Short-term Debt. . . . . . . . . . . . . . . . . . .       219,700          123,005
  Accounts Payable . . . . . . . . . . . . . . . . . .       242,161          235,787
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       164,425          161,406
  Interest Accrued . . . . . . . . . . . . . . . . . .        23,212           14,187
  Obligations Under Capital Leases . . . . . . . . . .        28,283           28,310
  Energy Marketing and Trading Contracts . . . . . . .       126,567           22,480
  Other. . . . . . . . . . . . . . . . . . . . . . . .        92,614           97,916

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       995,920          694,563

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       702,248          711,913

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        38,458           39,296

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       101,573           64,866

CONTINGENCIES (Note 4)

            TOTAL. . . . . . . . . . . . . . . . . . .    $4,590,892       $4,344,680


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,      

                                                                 1999          1998
                                                                   (in thousands)
<S>                                                          <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $  60,821     $  60,436
  Adjustments for Noncash Items:                                           
    Depreciation, Depletion and Amortization . . . . . . . .     45,129        43,259
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     (3,601)        3,466
    Deferred Fuel Costs (net). . . . . . . . . . . . . . . .     (7,227)      (11,000)
    Amortization of Deferred Property Taxes. . . . . . . . .     19,426        19,344
  Changes in Certain Current Assets and Liabilities:                       
    Accounts Receivable (net). . . . . . . . . . . . . . . .   (107,053)      (36,126)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    (20,409)       21,530
    Accrued Utility Revenues . . . . . . . . . . . . . . . .      4,082         2,491
    Prepayments. . . . . . . . . . . . . . . . . . . . . . .    (13,013)       (4,930)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .      6,374        (7,222)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .      3,019        (3,917)
    Interest Accrued . . . . . . . . . . . . . . . . . . . .      9,025         8,771
  Operating Reserves . . . . . . . . . . . . . . . . . . . .     17,519         9,548
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     24,364         6,164
        Net Cash Flows From Operating Activities . . . . . .     38,456       111,814

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .    (41,888)      (35,186) 
  Proceeds from Sale of Property and Other . . . . . . . . .        629         2,413 

        Net Cash Flows Used For Investing Activities . . . .    (41,259)      (32,773) 

FINANCING ACTIVITIES:
  Change in Short-term Debt (net). . . . . . . . . . . . . .     96,695        88,800 
  Retirement of Cumulative Preferred Stock . . . . . . . . .        (10)         - 
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (10,679)      (75,237) 
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (57,703)      (52,775) 
  Dividends Paid on Cumulative Preferred Stock . . . . . . .       (367)         (370) 
        Net Cash Flows From (Used For) Financing Activities.     27,936       (39,582)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     25,133        39,459
Cash and Cash Equivalents at Beginning of Period . . . . . .     89,652        44,203
Cash and Cash Equivalents at End of Period . . . . . . . . .  $ 114,785     $  83,662 


Supplemental Disclosure:
  Cash paid for interest net of capitalized  amounts was $10,562,000  and $10,377,000
  and for income  taxes was  $2,219,000 and $539,000 in 1999 and 1998,  respectively.
  Noncash  acquisitions  under  capital  leases  were $5,634,000  and  $10,294,000 in
  1999 and 1998, respectively.


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
               OHIO POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                          MARCH 31, 1999              
                           (UNAUDITED)
1.      GENERAL

             The accompanying unaudited consolidated financial
        statements should be read in conjunction with the 1998 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 April 1999 the Company called $88 million of first
        mortgage bonds, $40 million of 7.85% series due 2023, $40
        million of 6.875% series due 2003 and $8 million of 6.55%
        series due 2003, for early redemption in May.  Consequently,
        the bonds were reclassified as a current liability on the
        Consolidated Balance Sheets.

3.      NEW ACCOUNTING STANDARDS

             In the first quarter of 1999 the Company adopted the
        Financial Accounting Standards Board's Emerging Issues Task
        Force Consensus (EITF) 98-10, "Accounting for Contracts
        Involved in Energy Trading and Risk Management Activities". The
        EITF requires that all energy trading contracts be marked-to-market.
        The effect on the Consolidated Statements of Income
        of marking open trading contracts to market is deferred as
        regulatory assets or liabilities for those open trading
        transactions that are included in cost of service on a
        settlement basis for ratemaking purposes.  The adoption of the
        EITF did not have a material effect on results of operations,
        cash flows or financial condition.

4.      CONTINGENCIES

             As discussed in Note 4, of the Notes to Consolidated
        Financial Statements in the 1998 Annual Report, the
        deductibility of certain interest deductions related to
        American Electric Power's corporate owned life insurance (COLI)
        program for taxable years 1991-1996 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 COLI interest deductions through March 31,
        1999 would reduce earnings by approximately $117 million
        (including interest).  The Company has made no provision for
        any possible earnings impact from this matter. 

<PAGE>
             In 1998 the Company made payments of taxes and interest
        attributable to COLI interest deductions for taxable years
        1991-1997 to avoid the potential assessment by the IRS of any
        additional above market rate interest on the contested amount.
        These payments to the IRS are included on the Consolidated
        Balance Sheets in other property and investments pending the
        resolution of this matter.  The Company will seek refund,
        either administratively or through litigation, of all amounts
        paid plus interest.

             In order to resolve this issue, the Company filed suit
        against the United States in the US District Court for the
        Southern District of Ohio in March 1998.  Management believes
        that it has a meritorious position and will vigorously pursue
        this lawsuit.  In the event the resolution of this matter is
        unfavorable, it will have a material adverse impact on results
        of operations.

             The Company continues to be involved in certain other
        matters discussed in the 1998 Annual Report.
<PAGE>
<PAGE>
               OHIO POWER COMPANY AND SUBSIDIARIES
  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                      AND FINANCIAL CONDITION                  

            FIRST QUARTER 1999 vs. FIRST QUARTER 1998

RESULTS OF OPERATIONS
        Net income was virtually unchanged as operating income was
static reflecting flat operating revenues and steady operating
expenses.
        Income statement line items which changed significantly were:
                                              Increase (Decrease)
                                              (in millions)    %

        Fuel Expense . . . . . . . . . . . . .      $(4.1)       (2)
        Other Operation Expense. . . . . . . .        4.2         5
        Maintenance Expense. . . . . . . . . .       (5.1)      (17)
        Federal Income Taxes . . . . . . . . .        3.9        12

        The decrease in fuel expense is primarily due to a decrease in
the average cost of fuel consumed.
        Other operation expense increased due to accrual adjustments
related to incentive compensation payments made in the first
quarter.  The 1999 adjustment was unfavorable and the 1998
adjustment was favorable.
        The decrease in maintenance expense was primarily due to a
reduction in scheduled boiler plant maintenance at the Company's
generating plants in 1999.
        The increase in federal income taxes attributable to operations
is primarily due to an increase in pre-tax operating income and
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 $48 million.  Short-term debt increased by
$97 million from the beginning of 1999.
        In April 1999 the Company called $88 million of first mortgage
bonds, $40 million of 7.85% series due 2023, $40 million of 6.875%
series due 2003 and $8 million of 6.55% series due 2003, for early
redemption in May.  Consequently, the bonds were reclassified as a
current liability on the Consolidated Balance Sheets.<PAGE>
OTHER MATTERS
Market Risks
        The Company has certain market risks inherent in its business
activities 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, 1998.  Market risk represents the
risk of loss that may impact the Company due to adverse changes in
commodity market prices and interest rates.
        The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at March 31, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
        On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date.  In
addition, certain systems may fail to detect that the year 2000 is
a leap year.  Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company, through the AEP
System, is modifying or replacing its computer hardware and
software programs to minimize Y2K-related failures and repair such
failures if they occur.  This includes both information technology
(IT) systems, which are mainframe and client server applications,
and embedded logic (non-IT) systems, such as process controls for
energy production and delivery.  Externally, the problem is being
addressed with entities that interact with the Company, including
suppliers, customers, creditors, financial service organizations
and other parties essential to the Company's operations.  In the
course of the external evaluation, the Company has sought written
assurances from third parties regarding their state of Y2K
readiness.
        Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system. 
The Company, along with other electric utilities in North America,
regularly submits information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program. 
NERC then publicly reports summary information to the U.S.
Department of Energy (DOE) regarding the Y2K readiness of electric
utilities.  AEP participated in an industry-wide NERC-sponsored
drill on April 9, 1999 simulating the partial loss of voice and
data communications.  There were no major problems encountered with
relaying information with the use of backup telecommunications
systems.  AEP and other utilities plan to participate in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.
        The NERC report, dated April 30, 1999 and entitled: Preparing
the Electric Power Systems of North America for Transition to the
Year 2000 - A Status Report and Work Plan, First Quarter 1999,
states that: "With more than 75% of mission critical components
tested through March 31, 1999, findings in the field continue to
indicate that the transition through critical Y2K dates is expected
to have minimal impact on electric system operations in North
America."  The report also indicates that, "the risk of electrical
outages by Y2K appears to be no higher than the risks we already
experience" from incidents such as severe wind, ice, floods,
equipment failures and power shortages during an extremely hot or
cold period.
        Through the Electric Power Research Institute, an electric
utility industry-wide effort has been established to deal with Y2K
problems affecting embedded systems.  Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.
        The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
<PAGE>
Company's State of Readiness - Work has been prioritized in
accordance with business risk.  The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy, and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
        The following chart shows our progress toward becoming ready
for the Y2K as of March 31, 1999:
                                 IT SYSTEMS              NON-IT  SYSTEMS     
                         COMPLETION                 COMPLETION
                         DATE/ESTIMATED   PERCENT   DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of      2/24/1998        100%      5/31/1998       100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment: 
Identifying all Company    7/31/1998        100%       2/15/1999     100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.

Remediation/Testing: The
process of modifying,      6/30/1999     Mainframe:    6/30/1999*     65%
replacing or retiring                    94%
those mission critical and                       
high priority digital-based
systems with problems                    Client
processing dates in the                  Server:
Year 2000. Testing these                 56%
systems to ensure that after             
modifications have been                  
implemented correct date                 
processing occurs and full
functionality has been maintained.

*The Company is upgrading its 800 MHz trunked radio system, a mission critical
non-IT system, for Y2K readiness and it is anticipated that the upgrade should
be complete by September 30, 1999.

<PAGE>
        The Company continues to make steady progress toward the June
30, 1999 target date and anticipates completing the
remediation/testing work for mission critical and high-priority
systems by the June 30, 1999 target date except as noted in the
table.

Costs to Address the Company's Year 2000 Issues - Through March 31,
1999, the Company has spent $8 million on the Year 2000 project
and, estimates spending an additional $9 million to $12 million to
achieve Y2K readiness.  Most Y2K costs are for software
modifications, IT consultants and salaries and are expensed;
however, in certain cases the Company has acquired hardware that
was capitalized.  The Company intends to fund these expenditures
through internal sources.  Although significant, the cost of
becoming Y2K compliant is not expected to have a material impact on
the Company's results of operations, cash flows or financial
condition.

Risks of the Company's Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
        Automated power generation, transmission and distribution systems
        Telecommunications systems
        Energy trading systems
        Time-in-use, demand and remote metering systems for commercial
        and industrial customers and
        Work management and billing systems.
        The potential problems related to erroneous processing by, or
failure of, these systems are:
        Power service interruptions to customers
        Interrupted revenue data gathering and collection
        Poor customer relations resulting from delayed billing and
        settlement.
        Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restored.
        In addition, although relationships with third parties, such
as suppliers, customers and other electric utilities, are being
monitored, these third parties nonetheless represent a risk that
cannot be assessed with precision or controlled with certainty.
        Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Y2K-related issues may materially adversely affect the Company.

Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a draft Y2K contingency plan
and submitted it to the East Central Area Reliability Council in
December 1998 as part of NERC's review of regional and individual
electric utility contingency plans in 1999.  NERC's target date is
June 1999 for the completion of this contingency plan.  In
addition, the Company intends to establish contingency plans for
its business units to address alternatives if Y2K related failures
occur.  Contingency plans will be developed by the end of 1999.
        The Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place and
include:
        Availability of additional power generation reserves.
        Coal inventory of approximately 45 days of normal usage.
        Identifying critical operational locations, with key employees
        on duty at those locations during the Y2K transition.
<PAGE>
<PAGE>
                   PART II.  OTHER INFORMATION

Item 5.  Other Information.

American Electric Power Company, Inc. ("AEP") and Appalachian Power
Company ("APCo")

        Reference is made to pages 17 and 18 of the Annual Report on
Form 10-K for the year ended December 31, 1998 ("1998 10-K") for a
discussion of APCo's proposed transmission facilities.  On May 7,
1999, APCo filed its report on the Wyoming-Jacksons Ferry 765kV
line with the State Corporation Commission of Virginia as requested
by the Hearing Examiner in September 1998.  The report states that
the Wyoming-Jacksons Ferry line would cost approximately
$232,000,000 and recommends the use of a 90-mile long corridor. 
The revised estimated cost for the Wyoming-Cloverdale line is
$283,000,000.

AEP, AEP Generating Company ("AEGCo"), 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 pages 30 and 31 of the 1998 10-K for a
discussion of the NOx SIP Call issued by the U.S. Environmental
Protection Agency ("Federal EPA") and the Section 126 petitions
filed by eight northeastern states.  In April 1999, the states of
Maryland and New Jersey also filed Section 126 petitions.

        On April 30, 1999, Federal EPA took final action with respect
to the Section 126 petitions filed by the eight northeastern
states.  Federal EPA determined that six of the eight petitions
were partially approvable, thus triggering a determination that the
coal-fired generating plants in upwind states (including those of
the AEP System) would be subject to a 0.15 lbs. of NOx per million
Btu of heat input emission rate.  This emission rate will become
effective if the states in which the sources are located do not
submit an approvable State Implementation Plan by September 30,
1999 and if Federal EPA elects not to adopt a Federal
Implementation Plan by November 30, 1999.

        Reference is made to pages 31 and 32 of the 1998 10-K for a
discussion of global climate change.  As of April 9, 1999, 84
countries have signed the Kyoto Protocol and 8 countries have
ratified it.
<PAGE>
        Reference is made to page 33 of the 1998 10-K for a discussion
of a request issued to AEP under Section 114 of the Clean Air Act
focused on assessing compliance with the New Source Review and
Performance Standard provisions.  In April 1999, Federal EPA,
Regions III and V, issued additional requests seeking
identification of personnel at Sporn, Mitchell and Muskingum River
plants having knowledge of plant operations, including production,
maintenance and staff functions.  Federal EPA has also requested
information regarding projects at Tanners Creek Plant.  

AEP and OPCo

        Reference is made to page 42 of the 1998 10-K for a discussion
of litigation with Ormet Corporation involving the ownership of
sulfur dioxide allowances.  On March 25, 1999, Ormet appealed the
March 1999 District Court's decision to the U.S. Court of Appeals
for the Fourth Circuit.  The District Court decision had granted
summary judgment to OPCo and the AEP Service Corporation.   

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, 1999.
<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 12, 1999







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