THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND
SUBSIDIARIES IS REQUESTED TO BE 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 JUNE 30, 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., Canton, Ohio  44701
                Telephone (330) 456-8173

AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet
the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in General
Instruction H(2) to Form 10-Q.

Indicate by check mark whether the registrants (1) have filed all reports required to
be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrants were required to
file such reports), and (2) have been subject to such filing requirements for the past
90 days.
                                                            Yes   X          No

The number of shares outstanding of American Electric Power Company, Inc. Common Stock,
par value $6.50, at July 31, 1999 was 193,389,348.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                               FORM 10-Q

                  For The Quarter Ended June 30, 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 Comprehensive Income . . . . . . . . . . . . A-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2 - A-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4
             Consolidated Statements of Retained Earnings . . . . . . . . A-5
             Notes to Consolidated Financial Statements . . . . . . . . . A-6 - A-18
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . A-19- A-38

           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-9
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . C-10- C-18

           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-9
             Management's Narrative Analysis of Results of Operations . . D-10- D-11

           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-10
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . E-11- E-21

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


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

                                        FORM 10-Q

                                    For The Quarter Ended June 30, 1999
<CAPTION>
                                          INDEX

                                                                        Page
           <S>                                                          <C>
           Ohio Power Company and Subsidiaries:
             Consolidated Statements of Income and
               Consolidated Statements of Retained Earnings . . . . . . G-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . G-2 - G-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . G-4
             Notes to Consolidated Financial Statements . . . . . . . . G-5 - G-9
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . G-10- G-19


Part II. OTHER INFORMATION

           Item 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1
           Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3
           Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4

SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-6




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

<PAGE>
<PAGE>



FORWARD-LOOKING INFORMATION

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

       Electric load and customer growth.
       Abnormal weather conditions.
       Available sources and costs of fuels.
       Availability of generating capacity.
       The impact of the proposed merger with CSW including any regulatory
       conditions imposed on the merger or the inability to consummate the
       merger with CSW.
       The speed and degree to which competition is introduced to our power
       generation business.
       The structure and timing of a competitive market and its impact on energy
       prices or fixed rates.
       The ability to recover stranded costs in connection with
       possible/proposed deregulation of generation.
       New legislation and government regulations.
       The ability of AEP to successfully control its costs.
       The success of new business ventures.
       International developments affecting AEP's foreign investments.
       The economic climate and growth in AEP's service territory.
       Unforeseen events affecting AEP's nuclear plant which is on an extended
       safety related shutdown.
       Problems or failures related to Year 2000 readiness of computer
       software and hardware.
       Inflationary trends.
       Electricity and gas market prices.
       Interest rates
       Other risks and unforeseen events.

<PAGE>
<PAGE>
<TABLE>
      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                     CONSOLIDATED STATEMENTS OF INCOME
                  (in millions, except per-share amounts)
                                (UNAUDITED)
<CAPTION>
                                             Three Months Ended       Six Months Ended
                                                   June 30,               June 30,
                                              1999        1998        1999        1998
<S>                                          <C>         <C>         <C>         <C>
REVENUES:
  Domestic Regulated Electric Utilities. .   $1,501      $1,561      $3,051      $3,070
  Worldwide Non-regulated Electric and
    Gas Operations . . . . . . . . . . . .      142          (4)        286           8

          TOTAL REVENUES . . . . . . . . .    1,643       1,557       3,337       3,078

EXPENSES:
  Fuel and Purchased Power . . . . . . . .      494         554         985       1,039
  Maintenance and Other Operation. . . . .      469         437         896         848
  Depreciation and Amortization. . . . . .      149         144         297         288
  Taxes Other Than Federal Income Taxes. .      119         112         243         234
  Worldwide Non-regulated Electric and
    Gas Operations . . . . . . . . . . . .      127          16         250          31

          TOTAL EXPENSES . . . . . . . . .    1,358       1,263       2,671       2,440
OPERATING INCOME . . . . . . . . . . . . .      285         294         666         638
OTHER INCOME (LOSS), net . . . . . . . . .        2          13          (3)          9
INCOME BEFORE INTEREST, PREFERRED
  DIVIDENDS AND INCOME TAXES . . . . . . .      287         307         663         647

INTEREST AND PREFERRED DIVIDENDS . . . . .      135         109         267         215

INCOME BEFORE INCOME TAXES . . . . . . . .      152         198         396         432

INCOME TAXES . . . . . . . . . . . . . . .       64          80         157         163

NET INCOME . . . . . . . . . . . . . . . .   $   88      $  118      $  239      $  269

AVERAGE NUMBER OF SHARES OUTSTANDING . . .      193         191         192         190

EARNINGS PER SHARE . . . . . . . . . . . .    $0.46       $0.62       $1.24       $1.41

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



              CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                             Three Months Ended       Six Months Ended
                                                   June 30,               June 30,
                                              1999        1998        1999        1998

NET INCOME . . . . . . . . . . . . . . . .   $   88      $  118      $  239      $  269

OTHER COMPREHENSIVE INCOME:
  Foreign Currency Translation
    Adjustments. . . . . . . . . . . . . .       21          -           21          -
COMPREHENSIVE INCOME . . . . . . . . . . .   $  109      $  118      $  260      $  269
</TABLE>
<PAGE>
<PAGE>
<TABLE>
      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                                June 30,     December 31,
                                                                  1999           1998
                                                                    (in millions)
ASSETS
<S>                                                             <C>            <C>
CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . . . .      $   242        $   173
  Accounts Receivable (net). . . . . . . . . . . . . . . .          908            879
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . .          322            216
  Materials and Supplies . . . . . . . . . . . . . . . . .          306            280
  Accrued Utility Revenues . . . . . . . . . . . . . . . .          224            214
  Energy Marketing and Trading Contracts . . . . . . . . .          877            372
  Prepayments. . . . . . . . . . . . . . . . . . . . . . .          106             84

          TOTAL CURRENT ASSETS . . . . . . . . . . . . . .        2,985          2,218

PROPERTY, PLANT AND EQUIPMENT:
  Electric:
    Production . . . . . . . . . . . . . . . . . . . . . .        9,884          9,615
    Transmission . . . . . . . . . . . . . . . . . . . . .        3,772          3,692
    Distribution . . . . . . . . . . . . . . . . . . . . .        5,320          5,125
  Other (including gas and coal mining assets
    and nuclear fuel). . . . . . . . . . . . . . . . . . .        2,230          2,118
  Construction Work in Progress. . . . . . . . . . . . . .          597            801
          Total Property, Plant and Equipment. . . . . . .       21,803         21,351
  Accumulated Depreciation and Amortization. . . . . . . .        8,879          8,549

          NET PROPERTY, PLANT AND EQUIPMENT. . . . . . . .       12,924         12,802

REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . .        1,952          1,847



OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . .        2,726          2,616

            TOTAL. . . . . . . . . . . . . . . . . . . . .      $20,587        $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>
                                                               June 30,      December 31,
                                                                 1999            1998
                                                                    (in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S>                                                            <C>             <C>
CURRENT LIABILITIES:
  Accounts Payable . . . . . . . . . . . . . . . . . . . .     $   560         $   607
  Short-term Debt. . . . . . . . . . . . . . . . . . . . .         989             617
  Long-term Debt Due Within One Year . . . . . . . . . . .         957             206
  Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .         279             382
  Interest Accrued . . . . . . . . . . . . . . . . . . . .          76              75
  Obligations Under Capital Leases . . . . . . . . . . . .          86              82
  Energy Marketing and Trading Contracts . . . . . . . . .         860             360
  Other. . . . . . . . . . . . . . . . . . . . . . . . . .         491             472

          TOTAL CURRENT LIABILITIES. . . . . . . . . . . .       4,298           2,801

LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . .       6,117           6,800

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . .       2,618           2,601

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . .         340             351

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . . .         217             222

DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . . .         457             263

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . .       1,434           1,429

CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . . .         173             174

CONTINGENCIES (Note 9)

COMMON SHAREHOLDERS' EQUITY:
  Common Stock-Par Value $6.50:
                                1999          1998
    Shares Authorized . . . .600,000,000   600,000,000
    Shares Issued . . . . . .202,292,368   200,816,469
    (8,999,992 shares were held in treasury) . . . . . . .       1,315          1,305
  Paid-in Capital. . . . . . . . . . . . . . . . . . . . .       1,906          1,854

  Accumulated Other Comprehensive Income:
    Foreign Currency Translation Adjustments . . . . . . .          20             (1)
  Retained Earnings. . . . . . . . . . . . . . . . . . . .       1,692          1,684

          TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . . .       4,933          4,842

            TOTAL. . . . . . . . . . . . . . . . . . . . .     $20,587        $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>
                                                                      Six Months Ended
                                                                          June 30,
                                                                     1999         1998
                                                                       (in millions)
<S>                                                                 <C>          <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . .  $ 239        $ 269
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . . . . .    348          309
    Deferred Federal Income Taxes. . . . . . . . . . . . . . . . .     54           14
    Deferred Investment Tax Credits. . . . . . . . . . . . . . . .    (11)         (12)
    Amortization of Deferred Property Taxes. . . . . . . . . . . .     80           78
    Cook Restart Expense Deferral. . . . . . . . . . . . . . . . .    (60)         -
    Deferred Costs Under Fuel Clause Mechanisms. . . . . . . . . .    (60)         (47)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . . . . .    (29)        (200)
    Fuel, Materials and Supplies . . . . . . . . . . . . . . . . .   (132)         (31)
    Accrued Utility Revenues . . . . . . . . . . . . . . . . . . .    (10)          (8)
    Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . .    (22)         (14)
    Accounts Payable . . . . . . . . . . . . . . . . . . . . . . .    (47)         159
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . .   (103)         (78)
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . . .     35           39
  Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . .      4           92
        Net Cash Flows From Operating Activities . . . . . . . . .    286          570

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . . . . .   (402)        (364)
  Proceeds from Sale of Property and Other . . . . . . . . . . . .    (10)         (14)
        Net Cash Flows Used For Investing Activities . . . . . . .   (412)        (378)

FINANCING ACTIVITIES:
  Issuance of Common Stock . . . . . . . . . . . . . . . . . . . .     62           42
  Issuance of Long-term Debt . . . . . . . . . . . . . . . . . . .    323          611
  Change in Short-term Debt (net). . . . . . . . . . . . . . . . .    372          (49)
  Retirement of Long-term Debt . . . . . . . . . . . . . . . . . .   (331)        (483)
  Dividends Paid on Common Stock . . . . . . . . . . . . . . . . .   (231)        (229)
        Net Cash Flows From (Used For) Financing Activities. . . .    195         (108)

Net Increase in Cash and Cash Equivalents. . . . . . . . . . . . .     69           84
Cash and Cash Equivalents at Beginning of Period . . . . . . . . .    173           91
Cash and Cash Equivalents at End of Period . . . . . . . . . . . .  $ 242        $ 175

Supplemental Disclosure:
  Cash paid for  interest net of capitalized  amounts was $256 million and $206 million
  and for income taxes was $79 million and $117 million in 1999 and 1998, respectively.
  Noncash acquisitions  under capital leases  were $43 million and $85 million in 1999
  and 1998, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)
<CAPTION>
                                             Three Months Ended       Six Months Ended
                                                   June 30,                June 30,
                                              1999        1998        1999        1998
                                                           (in millions)
<S>                                          <C>         <C>         <C>         <C>
BALANCE AT BEGINNING OF PERIOD . . . . . .   $1,720      $1,642      $1,684      $1,605
NET INCOME . . . . . . . . . . . . . . . .       88         118         239         269

DEDUCTIONS:
  Cash Dividends Declared. . . . . . . . .      116         115         231         229

BALANCE AT END OF PERIOD . . . . . . . . .   $1,692      $1,645      $1,692      $1,645

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
  AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           JUNE 30, 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 AND RELATED ACTIVITIES

       During the first six months of 1999, subsidiaries issued
   $250 million of senior unsecured notes: $150 million at 6.60%
   due in 2009 and $100 million at 6.75% due in 2004.  Also $50
   million of pollution control revenue bonds at 5.15% due in 2026
   were issued and short-term debt borrowings increased by $372
   million.  In July 1999 an additional $150 million of senior
   unsecured notes at 6.875% due in 2004 were issued.

       Retirements of debt were: first mortgage bonds totaling
   $243 million with interest rates ranging from 6.55% to 8.43%
   and due dates ranging from 2003 to 2023, $50 million of
   pollution control revenue bonds at 7.40% due 2009 and a $25
   million term loan with an interest rate of 6.42%.

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
   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 new regulatory assets
   contained in a Virginia rate 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.

<PAGE>
4. RATE MATTERS

       The FERC issued orders 888 and 889 in April 1996 which
   required each public utility that owns or controls interstate
   transmission facilities to file an open access network and
   point-to-point transmission tariff that offers services
   comparable to the utility's own uses of its transmission
   system.  The orders also require utilities to functionally
   unbundle their services, by requiring them to use their own
   tariffs in making off-system and third-party sales.  As part
   of the orders, the FERC issued a pro-forma tariff which
   reflects the Commission's views on the minimum non-price terms
   and conditions for non-discriminatory transmission service.
   The orders also allow a utility to seek recovery of certain
   prudently-incurred stranded costs that result from unbundled
   transmission service.

       On July 9, 1996, the AEP System companies filed an Open
   Access Transmission Tariff conforming with the FERC's pro-forma
   transmission tariff, subject to the resolution of certain
   pricing issues.

       On July 29, 1999, the FERC approved a draft order which
   rules on the Company's pending Open Access Transmission Tariff.
   This approved order has certain unfavorable pricing issues for
   which the Company has 30 days to seek rehearing.  If the
   Commission's order is ultimately upheld the Company will have
   to make refunds including interest.  As of June 30, 1999 the
   Company has not made any provisions for a refund which is
   preliminarily estimated to be approximately $20 million.

5. INVESTMENT IN YORKSHIRE

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

                          Three Months Ended   Six Months Ended
                               June 30,            June 30,
                           1999       1998       1999     1998
                                      (in millions)
   Income Statement Data:
    Operating Revenues   $504.7     $503.9   $1,156.7 $1,167.1
    Operating Income       38.5       92.5      152.0    182.2
    Net Income (Loss)      (4.4)     (14.8)      30.2     (7.9)

       On August 12, 1999, the Office of Gas and Electricity
   Markets (the U.K. regulator of gas and electricity rates)
   published draft price proposals for the U.K.'s regional
   electric distribution businesses that would be effective for
   the five-year period beginning April 1, 2000.  The draft price
   proposals would require average reductions of 16% to 21%.  The
   proposed distribution rates for Yorkshire call for a 15% to 20%
   reduction in distribution revenues.  Yorkshire is in the
   process of evaluating the draft price proposals.

6. BUSINESS SEGMENTS

       The Company's principal business segment is its cost based
   rate regulated Domestic Electric Utility business consisting
   of seven regulated utility operating companies providing
   residential, commercial, industrial and wholesale electric
   services in seven Atlantic and Midwestern states.  Also
   included in this segment are the Company's electric power
   wholesale marketing and trading activities that are conducted
   as part of regulated operations and subject to cost of service
   rate regulation.  Worldwide Non-regulated Electric and Gas
   Operations are comprised of a Worldwide Energy Investments
   segment and the other segment.  The Worldwide 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 six months ending June 30,
   1999 and 1998 is shown in the following table:
<TABLE>
<CAPTION>
                                                   Worldwide Non-regulated
                                                 Electric and Gas Operations
                                 Regulated
                                 Domestic    World
                                 Electric    Wide Energy              Reconciling    AEP
                                 Utilities   Investments    Other     Adjustments    Consolidated
                                                         (in millions)
 <S>                           <C>            <C>           <C>           <C>         <C>
 June 30, 1999
   Revenues from
     external customers     $ 3,051       $  335         $ 57         $(106)       $ 3,337
   Revenues from
     transactions with other
     operating segments        -              28           78          (106)          -
   Segment net income (loss)    251           (1)         (11)          -              239
   Total assets              17,766        2,305          516           -           20,587
 June 30, 1998
   Revenues from
     external customers       3,070            9           (1)          -           3,078
   Revenues from
     transactions with other
     operating segments        -             -             -            -            -
   Segment net income (loss)    290          (15)          (6)          -             269
   Total assets              16,686          427          100           -          17,213
</TABLE>

7. MERGER

       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.  On July 29, 1999 applications
   were made with the Federal Communication Commission to
   authorize the transfer of control of licenses of several CSW
   entities to the Company.  AEP and CSW made a merger filing with
   the Department of Justice in July 1999.  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.

   FERC

       In November, 1998 the FERC issued an order establishing
   hearing procedures for the merger.  The 1998 FERC order
   indicated that the review of the proposed merger will address
   the issues of competition, market power and customer
   protection.  On May 25, 1999 AEP and CSW reached a settlement
   with the FERC trial staff resolving competition and rate issues
   relating to the merger.  On July 13, 1999 AEP and CSW reached
   an additional settlement with the FERC trial staff resolving
   additional issues.  The settlements were submitted to the FERC
   for approval.  Under the terms of the settlements, AEP filed
   with the FERC a regional transmission organization proposal
   whereby it will transfer the operation and control of AEP's
   bulk transmission facilities.  The settlements also cover rates
   for transmission services and ancillary service as well as
   resolving issues related to system integration agreements and
   confirm, subject to FERC guidance on certain elements, that the
   proposed generation divestiture of up to 550 megawatts of
   capacity will satisfy the staff's market power concerns.  The
   hearings began on June 29, 1999 and concluded on July 19, 1999.

       On June 28, 1999, the Company and CSW filed a motion with
   the FERC asking to waive the requirement for a post-hearing
   decision by an administrative law judge (ALJ) who presides over
   the merger hearing.  The motion indicated that the commission
   could then decide the matter based on the hearing record and
   briefs submitted by all interested parties.  On July 28, 1999,
   the FERC ordered the ALJ to issue an initial decision as soon
   as possible, but no later than November 24, 1999.  The
   commission concluded that it needed the benefit of the ALJ's
   opinion and therefore decided not to grant the request.  The
   procedural schedule that follows the ALJ's initial decision
   should allow the FERC to issue a final order in the first
   quarter of 2000.

<PAGE>
   Louisiana

       On July 29, 1999 the Louisiana Public Service Commission
   (LPSC) approved the merger between the Company and CSW subject
   to final FERC approval.  In granting approval, the LPSC also
   approved a stipulated settlement in which the Company and CSW
   agreed to share with SWEPCO's Louisiana customers merger
   savings created as a result of the merger over the eight years
   following its consummation.  The merger savings are estimated
   to total more than $18 million during that eight-year period.
   In addition the settlement also includes:

       A cap on base rates for five years after consummation of
       the merger;
       Sharing of benefits from off-system sales;
       Establishment of conditions for affiliate transactions
       with other AEP and CSW subsidiaries;
       Provisions to ensure continued quality of service; and
       Provisions to hold SWEPCO's Louisiana customers harmless
       for adverse effects of the merger, if any.

   Oklahoma

       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 in 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.  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.  Certain municipal and
   cooperative customers have appealed the OCC's merger approval
   order.

   Texas

       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 is composed of $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 Public Utility
   Commission of Texas held hearings on the merger on August 9 and
   10, 1999 and a final order is expected in the fourth quarter
   of 1999.  On August 11, 1999 AEP and CSW announced that
   settlement agreements with several Texas wholesale customer
   groups had been reached.  The agreements, which are subject to
   approval by the governing bodies of each of the wholesale
   customers, resolve certain issues raised in the merger
   proceeding and call for the wholesale customer groups to
   withdrawal their opposition to the merger in all regulatory
   approval proceedings.

   Indiana

       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 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 the FERC
   or SEC  proceedings.

   Kentucky

       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.  Although AEP did not believe
   that the KPSC has the jurisdictional authority to approve the
   merger, AEP reached a merger settlement agreement on May 24,
   1999 with key parties in Kentucky which the KPSC approved on
   June 14, 1999.  Under the terms of the Kentucky settlement, AEP
   has agreed to share net merger savings with Kentucky customers;
   establish performance standards that will maintain or improve
   customer service and system reliability; and to establish rules
   to protect consumers and promote fair competition.  The
   Kentucky customers' share of the net merger savings are
   expected to be approximately $28 million.  The key parties to
   the Kentucky settlement agreed not to oppose the merger during
   the FERC or the SEC proceedings.

   Other

       AEP and CSW have reached settlements with the Missouri
   Commission, the International Brotherhood of Electrical Workers
   (IBEW), representing employees of AEP and CSW, and the Utility
   Worker's Union of America (UWUA) representing AEP employees,
   and certain wholesale customers.  All have agreed not to oppose
   the merger in the 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.

   Completion of the Merger

       As of June 30, 1999, AEP had deferred $30 million of costs
   related to the merger on its consolidated balance sheet, which
   will be charged to expense if AEP and CSW are not successful
   in completing their proposed merger.  If the merger is
   consummated the deferred costs will be amortized over their
   recovery period, generally 5-years.

       The merger is conditioned upon, among other things, the
   approval of certain 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 for six months by either party as provided in the
   merger agreement.  Although consummation of the merger is
   expected to occur in the first quarter of 2000, the Company is
   unable to predict the outcome or the timing of the required
   regulatory proceedings.


<PAGE>
8. RESTRUCTURING LEGISLATION

   Virginia

       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 electricity
   supplier for retail customers will commence on January 1, 2002
   and be completed, subject to a finding by the Virginia State
   Corporation Commission that an effective competitive market
   exists, on January 1, 2004.

       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 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 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.

       Management has concluded that as of June 30, 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 and the wires
   charge as provided in the law.  The establishment of capped
   rates should enable the Company to determine its ability to
   recover stranded costs.  When capped rates and the wires charge
   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 the Company will have
   to write-off its generation-related regulatory assets to the
   extent that they cannot be recovered under provisions of the
   restructuring law and record any asset impairments in
   accordance with SFAS 121 "Accounting for the Impairment of
   Long-lived Assets and for Long-lived Assets to Be Disposed Of."
   An impairment loss would be recorded to the extent that the
   cost of impaired assets cannot be recovered through the
   transition recovery mechanisms provided by the law and future
   market prices.  Absent the determination in the regulatory
   process of capped rates and other pertinent information, it is
   not possible at this time to determine if any plants are
   impaired in accordance with SFAS 121.  The amount of regulatory
   assets recorded on the books applicable to the Virginia
   generating business at June 30, 1999 is estimated to be $60
   million before related tax effects.

       Should it not be possible under the Virginia law to recover
   all or a portion of the generation related regulatory assets,
   it could have a material adverse impact on results of
   operations.  An estimated determination of whether the Company
   will experience any asset impairment loss regarding its
   Virginia retail jurisdictional generating assets and any loss
   from a possible inability to recover generation related
   regulatory assets cannot be made until such time as the
   transition capped rates and the wires charge are determined
   under the law which is expected to be in the fourth quarter of
   2000.

   Ohio

       On July 6, 1999, the Governor of the State of Ohio signed
   The Ohio Electric Restructuring Act of 1999.  The Act provides
   for customer choice of electricity supplier and a residential
   rate reduction of 5% of the unbundled generation rate beginning
   on January 1, 2001.  The Act also provides for a five-year
   transition period to transition from cost based rates to market
   pricing for generation services.  It authorizes the Public
   Utilities Commission of Ohio (PUCO) to address certain major
   transition issues including unbundling of rates and the
   recovery of regulatory assets and other stranded transition
   costs.

       Retail electric services that will be competitive are
   defined in the Act as electric generation service, aggregation
   service, and power marketing and brokering.  The PUCO has been
   granted broad oversight responsibility under the Act.  The Act
   requires the PUCO to promulgate rules for competitive retail
   electric generation service.

       The Act further provides Ohio electric utilities with an
   opportunity to recover PUCO approved allowable transition costs
   through unbundled rates paid by customers who do not switch
   generation suppliers and through a wires charges by customers
   who switch generation suppliers.  Transition costs can include
   regulatory assets, impairments of generating assets and other
   stranded costs, employee severance and retraining costs and
   other costs.  Recovery of transition revenues can under certain
   circumstances extend beyond the five-year transition period but
   cannot continue beyond December 31, 2010.  The Company must
   file a transition plan with the PUCO by January 3, 2000 and the
   PUCO is required to issue a transition order no later than
   October 31, 2000.

       The Act also provides that the property tax assessment
   percentage on electric generation equipment be lowered from
   100% to 25% of value effective January 1, 2001.  Electric
   utilities will also become subject to the Ohio Corporate
   Franchise Tax and municipal income taxes on January 1, 2002.
   The last year for which electric utilities will pay the excise
   tax based on gross receipts is the year ending April 30, 2002.
   As of May 1, 2001 electric distribution companies will be
   subject to an excise tax based on kilowatt-hours sold to Ohio
   customers.  These changes should put the Company's generation
   operations on an equal level with other competitive businesses
   in Ohio regarding state taxation.

       As discussed in Note 2, "Effects of Regulation," of the
   Notes to Consolidated Financial Statements in the 1998 Annual
   Report, the Company defers as regulatory liabilities and assets
   certain revenues and expenses consistent with the regulatory
   process in accordance with SFAS 71.  At June 30, 1999 the
   amount of regulatory assets recorded on the books applicable
   to the generating business is estimated to be $640 million
   before related tax effects.  Whether the Company will have any
   additional stranded transition costs related to an economic
   impairment of its generating assets is dependent on several
   factors including the assumed future market price for
   electricity.  The Company intends to seek recovery in its
   transition filing of all regulatory assets and any other
   stranded transition costs which may be identified. At this time
   management is unable to predict the outcome of the regulatory
   process or its impact on results of operations, cash flows or
   financial condition.  Therefore, the Company will not be
   discontinuing application of SFAS 71 until the regulatory
   process is completed.

       Upon discontinuance of the application of SFAS 71 the
   Company will have to write off its generation-related
   regulatory assets and record any asset impairments in
   accordance with SFAS 121.  Absent the determination in the
   regulatory process of transition revenues and other pertinent
   information, it is not possible at this time to determine if
   any plants are impaired in accordance with SFAS 121.  Should
   the Company be granted recovery of its regulatory assets and/or
   any economic asset impairments it can record an offsetting
   regulatory asset.  Should the PUCO not approve the Company's
   request for recovery of its generation-related regulatory
   assets and/or other stranded transition costs it would have an
   adverse impact on future results of operations and possibly
   financial condition.  The Company does not expect to be able
   to determine the impact of the legislation on its financial
   statements until the regulatory process is complete.  The PUCO
   is required to complete its regulatory process no later than
   October 31, 2000.

9. 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 June 30, 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 is seeking refunds 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.

   Air Quality

       As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the US
   Environmental Protection Agency (Federal EPA) issued final
   rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which
   the generating plants of the Company and its AEP System
   affiliates are located.  The final rules were to be implemented
   through state implementation plans (SIPs).  SIPs are a
   procedural method used by each state to comply with Federal EPA
   rules.  The NOx SIP Call rule requires submission of revised
   SIPs by September 30, 1999.  A number of utilities, including
   the operating companies of the AEP System, filed petitions
   seeking a review of the final rule in the U.S. Court of Appeals
   for the District of Columbia Circuit (Appeals Court).  On May
   25, 1999, the Appeals Court ordered an indefinite stay of the
   September 30, 1999 deadline for submission of SIP revisions
   pending a further order of the court while arguments regarding
   the SIP Call rule are considered.

       On April 30, 1999, Federal EPA took final action with
   respect to petitions filed by eight northeastern states
   pursuant to Section 126 of the Clean Air Act.  Federal EPA
   approved portions of the states' petitions triggering emission
   reductions that are substantially the same as those that would
   otherwise have been required by the NOx SIP Call.  The
   imposition of these NOx reduction requirements on AEP System
   generating units would be approximately equivalent to the
   reductions contemplated by the stayed SIP Call rule.  On May
   28, and June 1, 1999, the Utility Air Regulatory Group and the
   Midwest Ozone Group, respectively, each filed a petition in the
   Appeals Court seeking review of Federal EPA's approval of
   portions of the northeastern states' petitions.  In the second
   quarter of 1999, three additional northeastern states filed
   Section 126 petitions with Federal EPA similar to those filed
   by the eight northeastern states.

       Preliminary estimates indicate that NOx compliance could
   result in required capital expenditures of approximately $1.5
   billion for the Company.  Compliance costs cannot be estimated
   with certainty and the actual costs incurred to comply could
   be significantly different from this preliminary estimate
   depending upon the compliance alternatives selected to achieve
   reductions in NOx emissions.  Unless such costs are recovered
   from customers through regulated rates and/or reflected in the
   future market price of electricity, they will have a material
   adverse effect on future results of operations, cash flows and
   possibly financial condition.

   Cook Nuclear 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
   that arose during an 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.  In 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 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.

       On June 24, 1999, the Boards of Directors of the Company
   and Indiana Michigan Power Company both approved a plan to
   restart the Cook Plant.  Unit 2 is scheduled to return to
   service in April 2000 and Unit 1 is to return to service in
   September 2000.  This approval follows a comprehensive systems
   readiness review of all operating systems at the Cook Plant.
   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.

       Management intends to replace the steam generator for Unit
   1 before the unit is returned to service.  Costs associated
   with the steam generator replacement are estimated to be
   approximately $165 million, which will be accounted for as a
   capital investment unrelated to the restart.  At June 30, 1999,
   $70 million has been spent on the steam generator replacement.

       The cost of electricity supplied to retail customers
   increased due to the outage of the two Cook Plant nuclear units
   since higher cost coal-fired generation and coal based
   purchased power is being substituted for the unavailable low
   cost nuclear generation. Actual replacement energy fuel costs
   that exceeded the estimated costs reflected in billings have
   been recorded as a regulatory asset under the Indiana and
   Michigan retail jurisdictional fuel cost recovery mechanisms.
   At June 30, 1999, the regulatory asset was $129 million.

       On March 30, 1999 the IURC approved a settlement agreement
   that resolves all matters related to the recovery of
   replacement energy fuel costs and all outage/restart 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'
   bills; the deferral of unrecovered fuel revenues accrued
   between September 9, 1997 and December 31, 1999, including the
   $52.3 million revenue portion of the $55 million billing
   credit; the deferral of up to $150 million of incremental
   operation and maintenance costs in 1999 for Cook Plant above
   the amount included in base rates; the amortization of the
   deferred 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 applied to customers' bills  during the
   months of July, August and September 1999.

       In June 1999 the Company announced that a settlement
   agreement for two open Michigan power supply cost recovery
   reconciliation cases had been reached with the staff of the
   Michigan Public Service Commission (MPSC).  The proposed
   settlement agreement would freeze rates and power supply costs
   for five years, allow for the amortization of deferred power
   supply cost for 1997, 1998 and 1999 over five years, allow for
   the deferral and amortization of non-fuel nuclear operation and
   maintenance expenses over five years and resolve all issues
   related to the Cook Plant extended outage.  At a hearing on
   June 30, 1999, the MPSC granted a continuance to the one
   intervenor who opposed the approval of the settlement
   agreement.  A hearing has been scheduled for August 13, 1999.

       Expenditures for the restart of the Cook units are
   estimated to total approximately $574 million and will be
   accounted for primarily as current period operation and
   maintenance expense in 1999 and 2000.  Through June 30, 1999,
   $192 million has been spent, of which $108 million was incurred
   in the first half of 1999.  Pursuant to the Indiana settlement
   agreement $60 million of incremental operation and maintenance
   costs were deferred through June 30, 1999.  The Indiana
   jurisdiction deferral is limited to $150 million of incremental
   restart costs incurred in 1999.  The pending Michigan
   settlement limits deferrals to $50 million of non-fuel
   operation and maintenance costs.

       The costs of the extended outage and restart efforts will
   have a material adverse effect on future results of operations,
   cash flows, and possibly financial condition through 2003.
   Management believes that the Cook units will be successfully
   returned to service by April and September 2000, however, if
   for some unknown reason the units are not returned to service
   or their return is delayed significantly it would have an even
   greater adverse effect on future results of operations, cash
   flows and financial condition.

<PAGE>
   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

           SECOND QUARTER 1999 vs. SECOND QUARTER 1998
                               AND
             YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998


RESULTS OF OPERATIONS
   Net income decreased $30 million or 25% in the second quarter
and $30 million or 11% in the year-to-date period due primarily to
an extended outage of the Company's nuclear plant and mild weather
in the second quarter.
   Income statement line items which changed significantly were:
                                      Increase (Decrease)
                                 Second Quarter  Year-To-Date
                                 (in millions) % (in millions) %

Revenues:
  Domestic Regulated Electric
   Utilities. . . . . . . . . . .    $(60)    (4)    $(19)    (1)
  Worldwide Non-regulated
   Operations . . . . . . . . . .     146    N.M.     278    N.M.
Fuel and Purchased Power Expense.     (60)   (11)     (54)    (5)
Maintenance and Other
 Operation Expense. . . . . . . .      32      7       48      6
Worldwide Non-regulated
 Operations Expense . . . . . . .     111    N.M.     219    N.M.
Other Income (Loss), net. . . . .     (11)   N.M.     (12)   N.M.
Interest and Preferred Dividends.      26     24       52     24
Income Taxes. . . . . . . . . . .     (16)   (20)      (6)    (4)

N.M. = Not Meaningful

   Revenues from domestic regulated electric utility operations
decreased in both periods reflecting lower wholesale prices and a
decrease in wholesale energy sales.  A decrease in sales to
residential customers reflecting mild weather also contributed to
the decrease in revenues for the second quarter.  The decline in
wholesale sales reflects milder springtime temperatures and the
termination of a contract to supply power to several municipal
customers.  Lower wholesale prices in 1999 reflect the effect of
reduced demand on prices.  Wholesale demand is affected by the
weather and the availability of non-affiliated generating units.
   The increase in revenues from worldwide non-regulated
operations was predominantly due to the acquisition in December
1998 of CitiPower, an Australian electric distribution utility, and
Louisiana Intrastate Gas, a midstream natural gas operation in
Louisiana.
   The decrease in fuel and purchased power expense was primarily
attributable to a decrease in purchases of power and a reduction in
prices reflecting the effects of mild weather on demand and prices.
   Maintenance and other operation expense increased due to the
cost of work to prepare the Company's nuclear generating units for
restart.  The units have been on an extended Nuclear Regulatory
Commission monitored outage (see Cook Nuclear Plant Shutdown
below).
   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 Louisiana Intrastate
Gas.
   The decrease in other income (loss) is primarily due to the
recognition of a provision for loss related to a Public Utilities
Commission of Ohio (PUCO) order which requires the Company to
reprice certain emission allowance transactions which are included
in the electric fuel rate factor of customers' bills.  The order
requires the Company to adjust the actual amount paid for
allowances purchased to the weighted average cost of allowances
surrendered to the United States Environmental Protection Agency
(Federal EPA) as a result of exceeding sulfur emission limitations
in order to make wholesale sales.
   Additional borrowings to fund the Company's non-regulated
operations, primarily the acquisitions of CitiPower and Louisiana
Intrastate Gas in December 1998, were the primary reason for the
significant increase in interest and preferred dividends.
   The decrease in income taxes is primarily attributable to a
decrease in United States federal income taxes which was due to a
decrease in pre-tax income.
FINANCIAL CONDITION
   Total plant and property additions including capital leases for
the first six months were $446 million.
   During the first six months of 1999 subsidiaries issued $324
million principal amount of long-term obligations at interest rates
ranging from 5.15% to 6.75%; retired $318 million principal amount
of long-term debt with interest rates ranging from 6.42% to 8.43%;
and increased short-term debt by $372 million from year-end
balances.
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.
On May 20, 1999, the other utility appealed this decision to the
U.S. Court of Appeals for the Federal Circuit.  I&M's case has been
stayed pending final resolution of the other utility's appeal.
Cook Nuclear Plant Shutdown
   As discussed in MDA in the 1998 Annual Report, both units of
the Cook Nuclear Plant were shut down by Indiana Michigan Power
Company (I&M) in September 1998 due to questions regarding the
operability of certain safety systems, which 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.  In 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 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.
   On June 24, 1999, the Boards of Directors of the Company and
Indiana Michigan Power Company both approved a plan to restart the
Cook Plant.  Unit 2 is scheduled to return to service in April 2000
and Unit 1 is to return to service in September 2000.  This
approval follows a comprehensive systems readiness review of all
operating systems at the Cook Plant.  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.
   Management intends to replace the steam generator for Unit 1
before the unit is returned to service.  Costs associated with the
steam generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart.  At June 30, 1999, $70 million has been
spent on the steam generator replacement.
   The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal based purchased power is being
substituted for the unavailable low cost nuclear generation.
Actual replacement energy fuel costs that exceeded the estimated
costs reflected in billings have been recorded as a regulatory
asset under the Indiana and Michigan retail jurisdictional fuel
cost recovery mechanisms.  At June 30, 1999, the regulatory asset
was $129 million.
   On March 30, 1999 the IURC approved a settlement agreement that
resolves all matters related to the recovery of replacement energy
fuel costs and all outage/restart 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' bills; the deferral of unrecovered fuel
revenues accrued between September 9, 1997 and December 31, 1999,
including the $52.3 million revenue portion of the $55 million
billing credit; the deferral of up to $150 million of incremental
operation and maintenance costs in 1999 for Cook Plant above the
amount included in base rates; the amortization of the deferred
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 applied to customers' bills  during the months of July, August
and September 1999.
   In June 1999 the Company announced that a settlement agreement
for two open Michigan power supply cost recovery reconciliation
cases had been reached with the staff of the Michigan Public
Service Commission (MPSC).  The proposed settlement agreement would
freeze rates and power supply costs for five years, allow for the
amortization of deferred power supply cost for 1997, 1998 and 1999
over five years, allow for the deferral and amortization of non-fuel nuclear
operation and maintenance expenses over five years and
resolve all issues related to the Cook Plant extended outage.  At
a hearing on June 30, 1999, the MPSC granted a continuance to the
one intervenor who opposed the approval of the settlement
agreement.  A hearing has been scheduled for August 13, 1999.
   Expenditures for the restart of the Cook units are estimated
to total approximately $574 million and will be accounted for
primarily as current period operation and maintenance expense in
1999 and 2000.  Through June 30, 1999, $192 million has been spent,
of which $108 million was incurred in the first half of 1999.
Pursuant to the Indiana settlement agreement $60 million of
incremental operation and maintenance costs were deferred through
June 30, 1999.  The Indiana jurisdiction deferral is limited to
$150 million of incremental restart costs incurred in 1999.  The
pending Michigan settlement limits deferrals to $50 million of non-fuel
operation and maintenance costs.

<PAGE>
   The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations, cash
flows, and possibly financial condition through 2003.  Management
believes that the Cook units will be successfully returned to
service by April and September 2000, however, if for some unknown
reason the units are not returned to service or their return is
delayed significantly it would have an even greater adverse effect
on future results of operations, cash flows and financial
condition.

Merger
   As discussed in Note 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), NRC and all
of CSW's state regulatory commissions: Arkansas, Louisiana,
Oklahoma and Texas.  On July 29, 1999 applications were made with
the Federal Communication Commission to authorize the transfer of
control of licenses of several CSW entities to the Company.  AEP
and CSW made a merger filing with the Department of Justice in July
1999.  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.

FERC
   In November, 1998 the FERC issued an order establishing hearing
procedures for the merger.  The 1998 FERC order indicated that the
review of the proposed merger will address the issues of
competition, market power and customer protection.  On May 25, 1999
AEP and CSW reached a settlement with the FERC trial staff
resolving competition and rate issues relating to the merger.  On
July 13, 1999 AEP and CSW reached an additional settlement with the
FERC trial staff resolving additional issues.  The settlements were
submitted to the FERC for approval.  Under the terms of the
settlements, AEP filed with the FERC a regional transmission
organization proposal whereby it will transfer the operation and
control of AEP's bulk transmission facilities.  The settlements
also cover rates for transmission services and ancillary service as
well as resolving issues related to system integration agreements
and confirm, subject to FERC guidance on certain elements, that the
proposed generation divestiture of up to 550 megawatts of capacity
will satisfy the staff's market power concerns.  The hearings began
on June 29, 1999 and concluded on July 19, 1999.
   On June 28, 1999, the Company and CSW filed a motion with the
FERC asking to waive the requirement for a post-hearing decision by
an administrative law judge (ALJ) who presides over the merger
hearing.  The motion indicated that the commission could then
decide the matter based on the hearing record and briefs submitted
by all interested parties.  On July 28, 1999, the FERC ordered the
ALJ to issue an initial decision as soon as possible, but no later
than November 24, 1999.  The commission concluded that it needed
the benefit of the ALJ's opinion and therefore decided not to grant
the request.  The procedural schedule that follows the ALJ's
initial decision should allow the FERC to issue a final order in
the first quarter of 2000.

Louisiana
   On July 29, 1999 the Louisiana Public Service Commission (LPSC)
approved the merger between the Company and CSW subject to final
FERC approval.  In granting approval, the LPSC also approved a
stipulated settlement in which the Company and CSW agreed to share
with SWEPCO's Louisiana customers merger savings created as a
result of the merger over the eight years following its
consummation.  The merger savings are estimated to total more than
$18 million during that eight-year period.  In addition the
settlement also includes:
   A cap on base rates for five years after consummation of the
   merger;
   Sharing of benefits from off-system sales;

   Establishment of conditions for affiliate transactions with
   other AEP and CSW subsidiaries;
   Provisions to ensure continued quality of service; and
   Provisions to hold SWEPCO's Louisiana customers harmless for
   adverse effects of the merger, if any.

Oklahoma
   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 in 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.  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.  Certain municipal and
cooperative customers have appealed the OCC's merger approval
order.

Texas
   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 is composed of $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 Public Utility
Commission of Texas held hearings on the merger on August 9 and 10,
1999 and a final order is expected in the fourth quarter of 1999.
On August 11, 1999 AEP and CSW announced that settlement agreements
with several Texas wholesale customer groups had been reached.  The
agreements, which are subject to approval by the governing bodies
of each of the wholesale customers, resolve certain issues raised
in the merger proceeding and call for the wholesale customer groups
to withdrawal their opposition to the merger in all regulatory
approval proceedings.

Indiana
   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 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 the FERC or SEC  proceedings.

Kentucky
   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.  Although AEP did not believe that the KPSC
has the jurisdictional authority to approve the merger, AEP reached
a merger settlement agreement on May 24, 1999 with key parties in
Kentucky which the KPSC approved on June 14, 1999.  Under the terms
of the Kentucky settlement, AEP has agreed to share net merger
savings with Kentucky customers; establish performance standards
that will maintain or improve customer service and system
reliability; and to establish rules to protect consumers and
promote fair competition.  The Kentucky customers' share of the net
merger savings are expected to be approximately $28 million.  The
key parties to the Kentucky settlement agreed not to oppose the
merger during the FERC or the SEC proceedings.

Other
   AEP and CSW have reached settlements with the Missouri
Commission, the International Brotherhood of Electrical Workers
(IBEW), representing employees of AEP and CSW, and the Utility
Worker's Union of America (UWUA) representing AEP employees, and
certain wholesale customers.  All have agreed not to oppose the
merger in the 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.

Completion of the Merger
   As of June 30, 1999, AEP had deferred $30 million of costs
related to the merger on its consolidated balance sheet, which will
be charged to expense if AEP and CSW are not successful in
completing their proposed merger.  If the merger is consummated the
deferred costs will be amortized over their recovery period,
generally 5-years.
   The merger is conditioned upon, among other things, the
approval of certain 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 for
six months by either party as provided in the merger agreement.
Although consummation of the merger is expected to occur in the
first quarter of 2000, the Company is unable to predict the outcome
or the timing of the required regulatory proceedings.

Restructuring Legislation
Virginia
   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 electricity supplier for retail customers
will commence on January 1, 2002 and be completed, subject to a
finding by the Virginia State Corporation Commission that an
effective competitive market exists, on January 1, 2004.
   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
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
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.
   Management has concluded that as of June 30, 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 and the wires charge as provided in
the law.  The establishment of capped rates should enable the
Company to determine its ability to recover stranded costs.  When
capped rates and the wires charge 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 the Company will have to write-off its generation-related
regulatory assets to the extent that they cannot be recovered under
provisions of the restructuring law and record any asset
impairments in accordance with SFAS 121 "Accounting for the
Impairment of Long-lived Assets and for Long-lived Assets to Be
Disposed Of."  An impairment loss would be recorded to the extent
that the cost of impaired assets cannot be recovered through the
transition recovery mechanisms provided by the law and future
market prices.  Absent the determination in the regulatory process
of capped rates and other pertinent information, it is not possible
at this time to determine if any plants are impaired in accordance
with SFAS 121.  The amount of regulatory assets recorded on the
books applicable to the Virginia generating business at June 30,
1999 is estimated to be $60 million before related tax effects.
   Should it not be possible under the Virginia law to recover all
or a portion of the generation related regulatory assets, it could
have a material adverse impact on results of operations.  An
estimated determination of whether the Company will experience any
asset impairment loss regarding its Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
generation related regulatory assets cannot be made until such time
as the transition capped rates and the wires charge are determined
under the law which is expected to be in the fourth quarter of
2000.
Ohio
   On July 6, 1999, the Governor of the State of Ohio signed The
Ohio Electric Restructuring Act of 1999.  The Act provides for
customer choice of electricity supplier and a residential rate
reduction of 5% of the unbundled generation rate beginning on
January 1, 2001.  The Act also provides for a five-year transition
period to transition from cost based rates to market pricing for
generation services.  It authorizes the Public Utilities Commission
of Ohio (PUCO) to address certain major transition issues including
unbundling of rates and the recovery of regulatory assets and other
stranded transition costs.
   Retail electric services that will be competitive are defined
in the Act as electric generation service, aggregation service, and
power marketing and brokering.  The PUCO has been granted broad
oversight responsibility under the Act.  The Act requires the PUCO
to promulgate rules for competitive retail electric generation
service.
   The Act further provides Ohio electric utilities with an
opportunity to recover PUCO approved allowable transition costs
through unbundled rates paid by customers who do not switch
generation suppliers and through a wires charges by customers who
switch generation suppliers.  Transition costs can include
regulatory assets, impairments of generating assets and other
stranded costs, employee severance and retraining costs and other
costs.  Recovery of transition revenues can under certain
circumstances extend beyond the five-year transition period but
cannot continue beyond December 31, 2010.  The Company must file a
transition plan with the PUCO by January 3, 2000 and the PUCO is
required to issue a transition order no later than October 31,
2000.
   The Act also provides that the property tax assessment
percentage on electric generation equipment be lowered from 100% to
25% of value effective January 1, 2001.  Electric utilities will
also become subject to the Ohio Corporate Franchise Tax and
municipal income taxes on January 1, 2002.  The last year for which
electric utilities will pay the excise tax based on gross receipts
is the year ending April 30, 2002.  As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on
kilowatt-hours sold to Ohio customers.  These changes should put
the Company's generation operations on an equal level with other
competitive businesses in Ohio regarding state taxation.
   As discussed in Note 2, "Effects of Regulation," of the Notes
to Consolidated Financial Statements in the 1998 Annual Report, the
Company defers as regulatory liabilities and assets certain
revenues and expenses consistent with the regulatory process in
accordance with SFAS 71.  At June 30, 1999 the amount of regulatory
assets recorded on the books applicable to the generating business
is estimated to be $640 million before related tax effects.
Whether the Company will have any additional stranded transition
costs related to an economic impairment of its generating assets is
dependent on several factors including the assumed future market
price for electricity.  The Company intends to seek recovery in its
transition filing of all regulatory assets and any other stranded
transition costs which may be identified. At this time management
is unable to predict the outcome of the regulatory process or its
impact on results of operations, cash flows or financial condition.
Therefore, the Company will not be discontinuing application of
SFAS 71 until the regulatory process is completed.
   Upon discontinuance of the application of SFAS 71 the Company
will have to write off its generation-related regulatory assets and
record any asset impairments in accordance with SFAS 121.  Absent
the determination in the regulatory process of transition revenues
and other pertinent information, it is not possible at this time to
determine if any plants are impaired in accordance with SFAS 121.
Should the Company be granted recovery of its regulatory assets
and/or any economic asset impairments it can record an offsetting
regulatory asset.  Should the PUCO not approve the Company's
request for recovery of its generation-related regulatory assets
and/or other stranded transition costs it would have an adverse
impact on future results of operations and possibly financial
condition.  The Company does not expect to be able to determine the
impact of the legislation on its financial statements until the
regulatory process is complete.  The PUCO is required to complete
its regulatory process no later than October 31, 2000.

<PAGE>
United Kingdom Price Reduction Proposal
   On August 12, 1999, the Office of Gas and Electricity Markets
(the U.K. regulator of gas and electricity rates) published draft
price proposals for the U.K.'s regional electric distribution
businesses that would be effective for the five-year period
beginning April 1, 2000.  The draft price proposals would require
average reductions of 16% to 21%.  The proposed distribution rates
for Yorkshire call for a 15% to 20% reduction in distribution
revenues.  Yorkshire is in the process of evaluating the draft
price proposals.

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 June 30, 1999 is not
materially different than at December 31, 1998.

Air Quality
   As discussed in MDA in the 1998 Annual Report, the US
Environmental Protection Agency (Federal EPA) issued final rules
which require reductions in nitrogen oxides (NOx) emissions in 22
eastern states, including the states in which the generating plants
of the Company and its AEP System affiliates are located.  The
final rules were to be implemented through state implementation
plans (SIPs).  SIPs are a procedural method used by each state to
comply with Federal EPA rules.  The NOx SIP Call rule requires
submission of revised SIPs by September 30, 1999.  A number of
utilities, including the operating companies of the AEP System,
filed petitions seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit (Appeals
Court).  On May 25, 1999, the Appeals Court ordered an indefinite
stay of the September 30, 1999 deadline for submission of SIP
revisions pending a further order of the court while arguments
regarding the SIP Call rule are considered.
   On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act.  Federal EPA approved portions of the
states' petitions triggering emission reductions that are
substantially the same as those that would otherwise have been
required by the NOx SIP Call.  The imposition of these NOx
reduction requirements on AEP System generating units would be
approximately equivalent to the reductions contemplated by the
stayed SIP Call rule.  On May 28, and June 1, 1999, the Utility Air
Regulatory Group and the Midwest Ozone Group, respectively, each
filed a petition in the Appeals Court seeking review of Federal
EPA's approval of portions of the northeastern states' petitions.
In the second quarter of 1999, three additional northeastern states
filed Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
   Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $1.5 billion for
the Company.  Compliance costs cannot be estimated with certainty
and the actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions.  Unless such costs are recovered from customers through
regulated rates and/or reflected in the future market price of
electricity, they will have a material adverse effect on future
results of operations, cash flows and possibly financial condition.


<PAGE>
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, has
submitted information to the North American Electric Reliability
Council (NERC) as part of NERC's Y2K readiness program.  NERC then
publicly reported summary information to the DOE regarding the Y2K
readiness of electric utilities.  The fourth and final NERC report,
dated August 3, 1999 and entitled: Preparing the Electric Power
Systems of North America for Transition to the Year 2000 - A Status
Report and Work Plan, Second Quarter 1999 states that: "Mission-critical
component testing indicates 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 caused 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.
   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.
   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 the Company's progress toward
becoming ready for Y2K as of June 30, 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    2/24/1998        100%      5/31/1998
   100%
of 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
  100%
replacing or retiring                    100%
those mission critical and
high priority digital-based
systems with problems                    Client
processing dates in the                  Server:
Year 2000. Testing these                 99%*
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.

* The Company is upgrading a meteorological reporting system used
at the Donald C. Cook Nuclear Plant, a mission critical IT system,
for Y2K readiness and it is anticipated that the upgrade should be
completed by December 15, 1999.

   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 August 31, 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 June 30,
1999, the Company has spent $35 million on the Y2K project and
estimates spending an additional $13 million to $21 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.  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.

<PAGE>
   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 Y2K contingency plan and
submitted it to the East Central Area Reliability Council (ECAR) as
part of NERC's review of regional and individual electric utility
contingency plans in 1999.  In addition, the Company is
establishing 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, in order to place
   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       Six Months Ended
                                                June 30,                June 30,
                                             1999      1998         1999        1998
                                                         (in thousands)
<S>                                        <C>        <C>         <C>         <C>
OPERATING REVENUES . . . . . . . . . . .   $51,612    $54,282     $104,439    $108,334

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    20,169     21,264       40,427      43,765
  Rent - Rockport Plant Unit 2 . . . . .    17,070     17,070       34,141      34,141
  Other Operation. . . . . . . . . . . .     2,092      2,724        5,462       5,373
  Maintenance. . . . . . . . . . . . . .     4,489      4,229        6,751       6,407
  Depreciation . . . . . . . . . . . . .     5,483      5,412       10,923      10,824
  Taxes Other Than Federal Income Taxes.     1,253        934        2,492       1,877
  Federal Income Taxes . . . . . . . . .        54        755          881       1,717

          TOTAL OPERATING EXPENSES . . .    50,610     52,388      101,077     104,104

OPERATING INCOME . . . . . . . . . . . .     1,002      1,894        3,362       4,230

NONOPERATING INCOME. . . . . . . . . . .       889        791        1,745       1,620

INCOME BEFORE INTEREST CHARGES . . . . .     1,891      2,685        5,107       5,850

INTEREST CHARGES . . . . . . . . . . . .       669        806        1,271       1,591

NET INCOME . . . . . . . . . . . . . . .   $ 1,222    $ 1,879     $  3,836    $  4,259



                      STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended       Six Months Ended
                                                June 30,                June 30,
                                             1999      1998         1999        1998
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . .    $4,311    $1,732       $2,770      $2,528

NET INCOME . . . . . . . . . . . . . . .     1,222     1,879        3,836       4,259

CASH DIVIDENDS DECLARED. . . . . . . . .     1,073     1,176        2,146       4,352

BALANCE AT END OF PERIOD . . . . . . . .    $4,460    $2,435       $4,460      $2,435



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>

                                                              June 30,     December 31,
                                                                1999           1998
                                                                   (in thousands)

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

  Production. . . . . . . . . . . . . . . . . . . . . . . .   $627,798       $630,260
  General . . . . . . . . . . . . . . . . . . . . . . . . .      1,933          2,009
  Construction Work in Progress . . . . . . . . . . . . . .      7,017          4,191

          Total Electric Utility Plant. . . . . . . . . . .    636,748        636,460

  Accumulated Depreciation. . . . . . . . . . . . . . . . .    284,326        277,855


          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .    352,422        358,605


CURRENT ASSETS:

  Cash and Cash Equivalents . . . . . . . . . . . . . . . .      1,561            232
  Accounts Receivable . . . . . . . . . . . . . . . . . . .     21,958         22,894
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .     26,811         11,308
  Materials and Supplies. . . . . . . . . . . . . . . . . .      3,877          3,900
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .         31            267


          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     54,238         38,601


REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      5,864          5,984


DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      2,522            702




            TOTAL . . . . . . . . . . . . . . . . . . . . .   $415,046       $403,892

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                          AEP GENERATING COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)


                                                              June 30,     December 31,
                                                                1999           1998
                                                                  (in thousands)
<CAPTION>
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 . . . . . . . . . . . . . . . . . . . . .     29,235         35,235
  Retained Earnings . . . . . . . . . . . . . . . . . . . .      4,460          2,770
          Total Common Shareholder's Equity . . . . . . . .     34,695         39,005
  Long-term Debt. . . . . . . . . . . . . . . . . . . . . .     44,796         44,792

          TOTAL CAPITALIZATION. . . . . . . . . . . . . . .     79,491         83,797

OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . .        752            896

CURRENT LIABILITIES:
  Short-term Debt - Notes Payable . . . . . . . . . . . . .     39,375         24,450
  Accounts Payable:
    General . . . . . . . . . . . . . . . . . . . . . . . .      7,902          6,419
    Affiliated Companies. . . . . . . . . . . . . . . . . .     11,190          6,177
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      7,704          3,227
  Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . .      4,963          4,963
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      2,852          6,023

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     73,986         51,259

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . .    130,545        133,330

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits . . . . . . . . . . . . .     64,885         66,562
  Amounts Due to Customers for Federal Income Tax . . . . .     27,488         28,644

          TOTAL REGULATORY LIABILITIES. . . . . . . . . . .     92,373         95,206

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     37,899         39,404

            TOTAL . . . . . . . . . . . . . . . . . . . . .   $415,046       $403,892

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                          AEP GENERATING COMPANY
                         STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                  Six Months Ended
                                                                      June 30,
                                                                1999           1998
                                                                   (in thousands)
<S>                                                           <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $  3,836       $  4,259
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . . .    10,923         10,824
    Deferred Federal Income Taxes. . . . . . . . . . . . . .    (2,661)         2,689
    Deferred Investment Tax Credits. . . . . . . . . . . . .    (1,677)        (1,681)
    Amortization of Deferred Gain on Sale
      and Leaseback - Rockport Plant Unit 2. . . . . . . . .    (2,785)        (2,785)
    Deferred Property Taxes. . . . . . . . . . . . . . . . .    (1,666)        (1,572)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable. . . . . . . . . . . . . . . . . . .       936         (1,803)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .   (15,480)        (5,700)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .     6,496          8,208
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .     4,477          1,330
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .    (3,413)           517
        Net Cash Flows From (Used For) Operating Activities.    (1,014)        14,286

INVESTING ACTIVITIES - Construction Expenditures . . . . . .    (4,436)        (3,769)

FINANCING ACTIVITIES:
  Return of Capital to Parent Company. . . . . . . . . . . .    (6,000)        (2,000)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .       -          (25,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .    14,925         23,200
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .    (2,146)        (4,352)
        Net Cash Flows From (Used For) Financing Activities.     6,779         (8,152)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     1,329          2,365
Cash and Cash Equivalents at Beginning of Period . . . . . .       232            237
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  1,561       $  2,602


Supplemental Disclosure:
  Cash  paid (received)  for interest net  of capitalized  amounts was $1,070,000 and
  $1,634,000  and  for income taxes was $1,268,000 and $(717,000) in  1999  and 1998,
  respectively.

See Notes to Financial Statements.
</TABLE>
<PAGE>
                          AEP GENERATING COMPANY
                       NOTES TO FINANCIAL STATEMENTS
                                JUNE 30, 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

                SECOND QUARTER 1999 vs. SECOND QUARTER 1998
                                    AND
                  YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 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 costs
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 declined $0.7 million or 35% in the second quarter and $0.4
million or 10% in the year-to-date period as a result of capital returned to
the Company's parent in 1998 and 1999.  Also contributing to the decrease in
net income for the quarter was a reduction to April 1999 billings to reflect
an adjustment to actual of estimated power production expenses included in
March 1999 billings.  The adjustment to actual expenses reduced revenues and
net income for the second quarter.
   Income statement line items which changed significantly were:
                                     Increase (Decrease)
                            Second Quarter     Year-to-Date
                            (in millions)   %  (in millions)   %

Operating Revenues . . . . .    $(2.7)     (5)     $(3.9)     (4)
Fuel Expense . . . . . . . .     (1.1)     (5)      (3.3)     (8)
Other Operation Expense. . .     (0.6)    (23)       0.1       2
Maintenance Expense. . . . .      0.3       6        0.3       5
Taxes Other Than Federal
  Income Taxes . . . . . . .      0.3      34        0.6      33
Federal Income Taxes . . . .     (0.7)    (93)      (0.8)    (49)
Interest Charges . . . . . .     (0.1)    (17)      (0.3)    (20)

   The decrease in operating revenues during the second quarter and the
year-to-date period reflects the recovery of lower operating expenses,
primarily fuel, and a reduction in capital cost from the return of capital.
Operating revenues for the second quarter were also reduced by the April 1999
billing adjustment.
   Fuel expense decreased reflecting a decrease in generation resulting from
planned maintenance outages of both Rockport units.

   The decline in other operation expense in the second quarter is primarily
due to a decrease in administrative and general expenses reflecting a
reduction in allocated employee salary and benefit costs and a reduction in
the FERC annual assessment.
   Maintenance expense increased due to the planned maintenance outages.
   Taxes other than federal income taxes increased due to an increase in
state income taxes which resulted from an increase in taxable income due to
the cessation of state tax depreciation for Rockport Plant Unit 1.
   Federal income taxes attributable to operations decreased due to a
decrease in pre-tax operating income and the reversal of deferred taxes in
excess of the statutory tax rate.
   The decline in interest charges in the second quarter was due to a
reduction in the average outstanding balance of short-term debt.  Interest
charges decreased in the year-to-date period primarily due to a reduction in
outstanding long-term debt reflecting a March 1998 redemption of $25 million
of pollution control revenue bonds.


<PAGE>
<PAGE>
<TABLE>         APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                           Three Months Ended        Six Months Ended
                                                June 30,                  June 30,
                                           1999         1998         1999          1998
                                                         (in thousands)
<S>                                      <C>          <C>         <C>            <C>
OPERATING REVENUES . . . . . . . . . . . $373,766     $403,080    $  801,468     $818,446

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   99,659      101,191       223,232      209,400
  Purchased Power. . . . . . . . . . . .   61,048       87,235       111,639      156,497
  Other Operation. . . . . . . . . . . .   60,162       62,442       122,911      117,309
  Maintenance. . . . . . . . . . . . . .   38,361       31,476        66,872       66,828
  Depreciation and Amortization. . . . .   37,224       35,788        73,775       71,193
  Taxes Other Than Federal Income Taxes.   30,066       29,934        60,041       60,178
  Federal Income Taxes . . . . . . . . .    4,147        8,822        28,292       26,600
          TOTAL OPERATING EXPENSES . . .  330,667      356,888       686,762      708,005
OPERATING INCOME . . . . . . . . . . . .   43,099       46,192       114,706      110,441
NONOPERATING INCOME (LOSS) . . . . . . .      315        1,561          (773)       1,174
INCOME BEFORE INTEREST CHARGES . . . . .   43,414       47,753       113,933      111,615
INTEREST CHARGES . . . . . . . . . . . .   32,378       32,629        63,636       63,292
NET INCOME . . . . . . . . . . . . . . .   11,036       15,124        50,297       48,323
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      673          678         1,348        1,147
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 10,363     $ 14,446    $   48,949     $ 47,176

               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended        Six Months Ended
                                                June 30,                  June 30,
                                           1999         1998        1999           1998
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $187,699     $210,545    $179,461       $207,544
NET INCOME . . . . . . . . . . . . . . .   11,036       15,124      50,297         48,323
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   30,348       29,729      60,696         59,458
    Cumulative Preferred Stock . . . . .      565          570       1,132            932
  Capital Stock Expense. . . . . . . . .      108          108         216            215

BALANCE AT END OF PERIOD . . . . . . . . $167,714     $195,262    $167,714       $195,262

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>
                                                            June 30,      December 31,
                                                              1999            1998
                                                                 (in thousands)
ASSETS
<S>                                                         <C>            <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .      $2,006,859     $1,979,180
  Transmission . . . . . . . . . . . . . . . . . . . .       1,132,344      1,118,726
  Distribution . . . . . . . . . . . . . . . . . . . .       1,675,056      1,641,523
  General. . . . . . . . . . . . . . . . . . . . . . .         239,257        228,464
  Construction Work in Progress. . . . . . . . . . . .         107,941        119,466
          Total Electric Utility Plant . . . . . . . .       5,161,457      5,087,359
  Accumulated Depreciation and Amortization. . . . . .       2,035,779      1,984,856

          NET ELECTRIC UTILITY PLANT . . . . . . . . .       3,125,678      3,102,503



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         140,694        111,020



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          30,081          7,755
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         112,483        122,746
    Affiliated Companies . . . . . . . . . . . . . . .          24,797         35,802
    Miscellaneous. . . . . . . . . . . . . . . . . . .          11,508          8,572
    Allowance for Uncollectible Accounts . . . . . . .          (2,883)        (2,234)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .          64,175         49,826
  Materials and Supplies . . . . . . . . . . . . . . .          63,726         60,440
  Accrued Utility Revenues . . . . . . . . . . . . . .          38,719         45,985
  Energy Marketing and Trading Contracts . . . . . . .         190,857         22,436
  Prepayments. . . . . . . . . . . . . . . . . . . . .           7,194          8,151

          TOTAL CURRENT ASSETS . . . . . . . . . . . .         540,657        359,479


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         421,647        433,516


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .          38,256         40,520

            TOTAL. . . . . . . . . . . . . . . . . . .      $4,266,932     $4,047,038

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          June 30,      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. . . . . . . . . . . . . . . . . . .      663,889         663,633
  Retained Earnings. . . . . . . . . . . . . . . . . .      167,714         179,461
          Total Common Shareholder's Equity. . . . . .    1,092,061       1,103,552
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .       19,116          19,359
    Subject to Mandatory Redemption. . . . . . . . . .       22,310          22,310
  Long-term Debt . . . . . . . . . . . . . . . . . . .    1,449,232       1,472,451

          TOTAL CAPITALIZATION . . . . . . . . . . . .    2,582,719       2,617,672

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .      131,027         120,281

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .      176,005          80,004
  Short-term Debt. . . . . . . . . . . . . . . . . . .      115,150          76,400
  Accounts Payable . . . . . . . . . . . . . . . . . .       85,718         110,882
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       35,791          35,719
  Customer Deposits. . . . . . . . . . . . . . . . . .       13,257          14,123
  Interest Accrued . . . . . . . . . . . . . . . . . .       20,017          19,990
  Revenue Refunds Accrued. . . . . . . . . . . . . . .       22,237          95,267
  Energy Marketing and Trading Contracts . . . . . . .      191,801          24,076
  Other. . . . . . . . . . . . . . . . . . . . . . . .       81,663          78,808

          TOTAL CURRENT LIABILITIES. . . . . . . . . .      741,639         535,269

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      653,003         643,711

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       59,887          62,231

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       98,657          67,874

CONTINGENCIES (Note 6)

            TOTAL. . . . . . . . . . . . . . . . . . .   $4,266,932      $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>
                                                                    Six Months Ended
                                                                        June 30,
                                                                   1999          1998
                                                                     (in thousands)
<S>                                                             <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . .  $  50,297     $  48,323
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . . .     74,302        71,825
    Deferred Federal Income Taxes. . . . . . . . . . . . . . .     13,895         2,151
    Deferred Investment Tax Credits. . . . . . . . . . . . . .     (2,344)       (2,366)
    Deferred Power Supply Costs (net). . . . . . . . . . . . .     23,208        15,474
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . . .     18,981        (1,367)
    Fuel, Materials and Supplies . . . . . . . . . . . . . . .    (17,635)      (14,079)
    Accrued Utility Revenues . . . . . . . . . . . . . . . . .      7,266        14,726
    Accounts Payable . . . . . . . . . . . . . . . . . . . . .    (25,164)      (20,170)
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . . .    (73,030)       37,862
  Other (net). . . . . . . . . . . . . . . . . . . . . . . . .     (9,128)        5,342
        Net Cash Flows From Operating Activities . . . . . . .     60,648       157,721

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . . .    (86,808)      (89,608)
  Proceeds from Sale of Property . . . . . . . . . . . . . . .        200           880
        Net Cash Flows Used For Investing Activities . . . . .    (86,608)      (88,728)

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . . .       -           25,000
  Issuance of Long-term Debt . . . . . . . . . . . . . . . . .    148,751       193,431
  Change in Short-term Debt (net). . . . . . . . . . . . . . .     38,750       (89,300)
  Retirement of Cumulative Preferred Stock . . . . . . . . . .       (149)         (190)
  Retirement of Long-term Debt . . . . . . . . . . . . . . . .    (77,236)     (138,471)
  Dividends Paid on Common Stock . . . . . . . . . . . . . . .    (60,696)      (59,458)
  Dividends Paid on Cumulative Preferred Stock . . . . . . . .     (1,134)       (1,142)
        Net Cash Flows From (Used For) Financing Activities. .     48,286       (70,130)

Net Increase (Decrease) in Cash and Cash Equivalents . . . . .     22,326        (1,137)
Cash and Cash Equivalents at Beginning of Period . . . . . . .      7,755         6,947
Cash and Cash Equivalents at End of Period . . . . . . . . . .  $  30,081     $   5,810

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $61,693,000 and $62,272,000 and
  for  income  taxes  was  $18,062,000 and $30,981,000 in  1999 and 1998, respectively.
  Noncash  acquisitions under  capital  leases were  $8,845,000 and $11,893,000 in 1999
  and 1998, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
            APPALACHIAN POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           JUNE 30, 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 May 1999 the Company issued $150 million of 6.60% senior
   unsecured notes due 2009.  During the first six months of 1999,
   the Company reacquired the following first mortgage bonds for
   $77 million.
                                             Principal
                                             Amount
        % Rate        Due Date               Reacquired
                                           (in thousands)
        8.43          June 1, 2022           $37,471
        7.80          May 1, 2023              9,763
        7.90          June 1, 2023            30,000

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 electricity
   supplier for retail customers will commence on January 1, 2002
   and be completed, subject to a finding by the Virginia State
   Corporation Commission that an effective competitive market
   exists, on January 1, 2004.

       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 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 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.

<PAGE>
       Management has concluded that as of June 30, 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 and the wires
   charge as provided in the law.  The establishment of capped
   rates should enable the Company to determine its ability to
   recover stranded costs.  When capped rates and the wires charge
   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 the Company will have
   to write-off its generation-related regulatory assets to the
   extent that they cannot be recovered under provisions of the
   restructuring law and record any asset impairments in
   accordance with SFAS 121 "Accounting for the Impairment of
   Long-lived Assets and for Long-lived Assets to Be Disposed Of."
   An impairment loss would be recorded to the extent that the
   cost of impaired assets cannot be recovered through the
   transition recovery mechanisms provided by the law and future
   market prices.  Absent the determination in the regulatory
   process of capped rates and other pertinent information, it is
   not possible at this time to determine if any of the Company's
   plants are impaired in accordance with SFAS 121.  The amount
   of regulatory assets recorded on the books applicable to the
   Virginia generating business at June 30, 1999 is estimated to
   be $60 million before related tax effects.

       Should it not be possible under the Virginia law to recover
   all or a portion of the generation related regulatory assets,
   it could have a material adverse impact on results of
   operations.  An estimated determination of whether the Company
   will experience any asset impairment loss regarding its
   Virginia retail jurisdictional generating assets and any loss
   from a possible inability to recover generation related
   regulatory assets cannot be made until such time as the
   transition capped rates and the wires charge are determined
   under the law which is expected to be in the fourth quarter of
   2000.

4. RATE MATTERS

       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.  In April 1999, the FERC denied the rehearing
   request.  The Company completed the FERC ordered refund to
   customers of $46.8 million including interest in July 1999.
   A liability for the refunds and interest had previously been
   recorded by the Company.

       The FERC issued orders 888 and 889 in April 1996 which
   required each public utility that owns or controls interstate
   transmission facilities to file an open access network and
   point-to-point transmission tariff that offers services
   comparable to the utility's own uses of its transmission
   system.  The orders also require utilities to functionally
   unbundle their services, by requiring them to use their own
   tariffs in making off-system and third-party sales.  As part
   of the orders, the FERC issued a pro-forma tariff which
   reflects the Commission's views on the minimum non-price terms
   and conditions for non-discriminatory transmission service.
   The orders also allow a utility to seek recovery of certain
   prudently-incurred stranded costs that result from unbundled
   transmission service.

       On July 9, 1996, the AEP System companies filed an Open
   Access Transmission Tariff conforming with the FERC's pro-forma
   transmission tariff, subject to the resolution of certain
   pricing issues.

       On July 29, 1999, the FERC approved a draft order which
   rules on the AEP System's pending Open Access Transmission
   Tariff.  This approved order has certain unfavorable pricing
   issues for which the AEP System has 30 days to seek rehearing.
   If the Commission's order is ultimately upheld the Company as
   a member of the AEP System will have to make refunds including
   interest.  As of June 30, 1999 the Company has not made any
   provisions for its share of a potential refund which is
   preliminarily estimated to be approximately $6 million.

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 $2.3 million for the six months
   ended June 30, 1999 is included in net income as a result of
   an agreed prohibition against establishing new regulatory
   assets in a February 1999 Virginia SCC approved 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 June 30,
   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 is seeking refunds
   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.

   Air Quality

       As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the U.S.
   Environmental Protection Agency (Federal EPA) issued final
   rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which
   the generating plants of the Company and its AEP System
   affiliates are located.  The final rules were to be implemented
   through state implementation plans (SIPs).  SIPs are a
   procedural method used by each state to comply with Federal EPA
   rules.  The NOx SIP Call rule requires submission of revised
   SIPs by September 30, 1999.  A number of utilities, including
   the Company and its AEP System affiliates, filed petitions
   seeking a review of the final rule in the U.S. Court of Appeals
   for the District of Columbia Circuit (Appeals Court).  On May
   25, 1999, the Appeals Court ordered an indefinite stay of the
   September 30, 1999 deadline for submission of SIP revisions
   pending a further order of the court while arguments regarding
   the SIP Call rule are considered.

       On April 30, 1999, Federal EPA took final action with
   respect to petitions filed by eight northeastern states
   pursuant to Section 126 of the Clean Air Act.  Federal EPA
   approved portions of the states' petitions triggering emission
   reductions that are substantially the same as those that would
   otherwise have been required by the NOx SIP Call.  The
   imposition of these NOx reduction requirements on AEP System
   generating units would be approximately equivalent to the
   reductions contemplated by the stayed SIP Call rule.  On May
   28, and June 1, 1999, the Utility Air Regulatory Group and the
   Midwest Ozone Group, respectively, each filed a petition in the
   Appeals Court seeking review of Federal EPA's approval of
   portions of the northeastern states' petitions.  In the second
   quarter of 1999, three additional northeastern states filed
   Section 126 petitions with Federal EPA similar to those filed
   by the eight northeastern states.

       Preliminary estimates indicate that NOx compliance could
   result in required capital expenditures of approximately $410
   million for the Company.  Compliance costs cannot be estimated
   with certainty and the actual costs incurred to comply could
   be significantly different from this preliminary estimate
   depending upon the compliance alternatives selected to achieve
   reductions in NOx emissions.  Unless such costs are recovered
   from customers through regulated rates and/or reflected in the
   future market price of electricity, they will have a material
   adverse effect on future results of operations, cash flows and
   possibly financial condition.

   Other

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

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

           SECOND QUARTER 1999 vs. SECOND QUARTER 1998
                               AND
             YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
   Net income decreased $4.1 million or 27% in the second quarter
due to a decline in residential and wholesale sales.  The increase
in net income of $2 million or 4% in the year-to-date period is due
to increased retail sales reflecting colder winter weather.
   Income statement line items which changed significantly were:
                                     Increase (Decrease)
                             Second Quarter       Year-to-Date
                            (in millions)  %   (in millions)   %

Operating Revenues . . . . .   $(29.3)    (7)     $(17.0)     (2)
Fuel Expense . . . . . . . .     (1.5)    (2)       13.8       7
Purchased Power Expense. . .    (26.2)   (30)      (44.9)    (29)
Other Operation Expense. . .     (2.3)    (4)        5.6       5
Maintenance Expense. . . . .      6.9     22         0.0       -
Federal Income Taxes . . . .     (4.7)   (53)        1.7       6

   Operating revenues decreased for both the second quarter and
year-to-date period due predominantly to a decline in wholesale
sales.  The reduction in wholesale sales in the year-to-date period
was partly offset by an increase in more profitable retail sales in
the first quarter.  Also contributing to the second quarter decline
was a decrease in residential sales of 8% reflecting milder spring
weather.  The reduction in wholesale sales is largely attributable
to the termination of a contract with several municipal customers
and mild weather in the second quarter.
   The increase in fuel expense in the year-to-date period was due
to an increase in generation to meet the increase in retail demand
during the first quarter.  A reduction in the net cost of fuel
consumed reflecting lower prices for coal burned partly offset the
effect of the increased generation.
   Purchased power expense decreased in both periods reflecting
a decline in purchases from unaffiliated entities and the American
Electric Power System Power Pool and a lower average price.  The
decrease in the average price reflects the reduced demand for
wholesale energy.  The need to purchase power decreased due to the
decline in wholesale sales and the increase in generation in the
year-to-date period.
   A reduction in employee benefit costs as a result of accrual
adjustments for worker's compensation accounted for the decrease in
other operation expense in the second quarter.  For the year-to-date period,
other operation expense increased due to employee
incentive compensation plan accrual adjustments.
   Maintenance expense increased in the second quarter as a result
of outages at Amos and Kanawha River plants for boiler repairs.
   The decrease in federal income tax expense attributable to
operations in the second quarter was primarily due to a decrease in
pre-tax operating income.
FINANCIAL CONDITION
   Total plant and property additions including capital leases for
the first six months of 1999 were $96 million.
   During the first six months of 1999, the Company issued one
series of senior unsecured notes of $150 million with a rate of
6.60% due in 2009 and redeemed $77 million principal amount of
first mortgage bonds with interest rates from 7.8% to 8.43%.
Short-term debt increased by $39 million from year-end balances.
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 electricity supplier for retail customers
will commence on January 1, 2002 and be completed, subject to a
finding by the Virginia State Corporation Commission that an
effective competitive market exists, on January 1, 2004.
   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
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
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.
   Management has concluded that as of June 30, 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 and the wires charge as provided in
the law.  The establishment of capped rates should enable the
Company to determine its ability to recover stranded costs.  When
capped rates and the wires charge 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 the Company will have to write-off its generation-related
regulatory assets to the extent that they cannot be recovered under
provisions of the restructuring law and record any asset
impairments in accordance with SFAS 121 "Accounting for the
Impairment of Long-lived Assets and for Long-lived Assets to Be
Disposed Of."  An impairment loss would be recorded to the extent
that the cost of impaired assets cannot be recovered through the
transition recovery mechanisms provided by the law and future
market prices.  Absent the determination in the regulatory process
of capped rates and other pertinent information, it is not possible
at this time to determine if any of the Company's plants are
impaired in accordance with SFAS 121.  The amount of regulatory
assets recorded on the books applicable to the Virginia generating
business at June 30, 1999 is estimated to be $60 million before
related tax effects.
   Should it not be possible under the Virginia law to recover all
or a portion of the generation related regulatory assets, it could
have a material adverse impact on results of operations.  An
estimated determination of whether the Company will experience any
asset impairment loss regarding its Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
generation related regulatory assets cannot be made until such time
as the transition capped rates and the wires charge are determined
under the law which is expected to be in the fourth quarter of
2000.

<PAGE>
Air Quality
   As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, Federal EPA issued final
rules which require reductions in nitrogen oxides (NOx) emissions
in 22 eastern states, including the states in which the generating
plants of the Company and its AEP System affiliates are located.
The final rules were to be implemented through state implementation
plans (SIPs).  SIPs are a procedural method used by each state to
comply with Federal EPA rules.  The NOx SIP Call rule requires
submission of revised SIPs by September 30, 1999.  A number of
utilities, including the Company and its AEP System affiliates,
filed petitions seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit (Appeals
Court).  On May 25, 1999, the Appeals Court ordered an indefinite
stay of the September 30, 1999 deadline for submission of SIP
revisions pending a further order of the court while arguments
regarding the SIP Call rule are considered.
   On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act.  Federal EPA approved portions of the
states' petitions triggering emission reductions that are
substantially the same as those that would otherwise have been
required by the NOx SIP Call.  The imposition of these NOx
reduction requirements on AEP System generating units would be
approximately equivalent to the reductions contemplated by the
stayed SIP Call rule.  On May 28, and June 1, 1999, the Utility Air
Regulatory Group and the Midwest Ozone Group, respectively, each
filed a petition in the Appeals Court seeking review of Federal
EPA's approval of portions of the northeastern states' petitions.
In the second quarter of 1999, three additional northeastern states
filed Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
   Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $410 million for
the Company.  Compliance costs cannot be estimated with certainty
and the actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions.  Unless such costs are recovered from customers through
regulated rates and/or reflected in the future market price of
electricity, they will have a material adverse effect on future
results of operations, cash flows and possibly financial condition.
Market Risks
   The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates.  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 June 30, 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,
has submitted information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reported summary information to the U.S.
Department of Energy (DOE) regarding the Y2K readiness of electric
utilities.  The fourth and final NERC report, dated August 3, 1999
and entitled: Preparing the Electric Power Systems of North America
for Transition to the Year 2000 - A Status Report and Work Plan,
Second Quarter 1999, states that: "Mission-critical component
testing indicates 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 caused 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.
   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.
   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 the Company's progress toward
becoming ready for the Y2K as of June 30, 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
  100%
replacing or retiring                    100%
those mission critical and
high priority digital-based
systems with problems                    Client
processing dates in the                  Server:
Year 2000. Testing these                 100%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.

Costs to Address the Company's Year 2000 Issues - Through June 30,
1999, the Company has spent $11 million on the Y2K project and,
estimates spending an additional $4 million to $6 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.  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 Y2K contingency plan and
submitted it to the East Central Area Reliability Council as part
of NERC's review of regional and individual electric utility
contingency plans in 1999.  In addition, the Company is
establishing 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.
   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, in order to place
   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        Six Months Ended
                                                June 30,                 June 30,
                                           1999         1998        1999         1998
                                                         (in thousands)
<S>                                      <C>          <C>         <C>          <C>
OPERATING REVENUES . . . . . . . . . . . $301,419     $298,263    $580,486     $564,662
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   49,144       46,860      95,000       93,840
  Purchased Power. . . . . . . . . . . .   59,255       58,782     114,446      106,619
  Other Operation. . . . . . . . . . . .   46,514       46,783      92,483       91,365
  Maintenance. . . . . . . . . . . . . .   18,374       14,889      32,320       29,196
  Depreciation . . . . . . . . . . . . .   23,522       22,844      46,706       45,694
  Taxes Other Than Federal Income Taxes.   30,051       27,690      61,129       57,626
  Federal Income Taxes . . . . . . . . .   20,086       23,264      37,882       37,942
          TOTAL OPERATING EXPENSES . . .  246,946      241,112     479,966      462,282
OPERATING INCOME . . . . . . . . . . . .   54,473       57,151     100,520      102,380
NONOPERATING INCOME (LOSS) . . . . . . .     (478)       1,256        (117)       1,228
INCOME BEFORE INTEREST CHARGES . . . . .   53,995       58,407     100,403      103,608
INTEREST CHARGES . . . . . . . . . . . .   19,436       19,665      38,426       39,221
NET INCOME . . . . . . . . . . . . . . .   34,559       38,742      61,977       64,387
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      532          532       1,065        1,065
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 34,027     $ 38,210    $ 60,912     $ 63,322



               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended        Six Months Ended
                                                June 30,                 June 30,
                                           1999         1998        1999         1998
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $191,327     $142,623    $186,441     $138,172
NET INCOME . . . . . . . . . . . . . . .   34,559       38,742      61,977       64,387
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   21,999       20,661      43,998       41,322
    Cumulative Preferred Stock . . . . .      438          438         875          875
  Capital Stock Expense. . . . . . . . .       95           95         191          191
BALANCE AT END OF PERIOD . . . . . . . . $203,354     $160,171    $203,354     $160,171

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>
                                                            June 30,      December 31,
                                                              1999            1998
                                                                 (in thousands)
ASSETS
<S>                                                        <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $1,535,336      $1,526,869
  Transmission . . . . . . . . . . . . . . . . . . . .        346,714         339,934
  Distribution . . . . . . . . . . . . . . . . . . . .        971,086         938,283
  General. . . . . . . . . . . . . . . . . . . . . . .        134,273         130,002
  Construction Work in Progress. . . . . . . . . . . .        103,598         118,477
          Total Electric Utility Plant . . . . . . . .      3,091,007       3,053,565

  Accumulated Depreciation . . . . . . . . . . . . . .      1,171,875       1,134,348

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      1,919,132       1,919,217


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         95,506          73,088


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          7,850           7,206
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         81,118          89,522
    Affiliated Companies . . . . . . . . . . . . . . .         33,808          17,966
    Miscellaneous. . . . . . . . . . . . . . . . . . .          5,847          11,989
    Allowance for Uncollectible Accounts . . . . . . .         (3,093)         (2,598)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         19,753          22,140
  Materials and Supplies . . . . . . . . . . . . . . .         37,836          33,263
  Accrued Utility Revenues . . . . . . . . . . . . . .         53,625          40,127
  Energy Marketing and Trading Contracts . . . . . . .        111,655          12,670
  Prepayments. . . . . . . . . . . . . . . . . . . . .         37,801          29,084

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        386,200         261,369


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        339,480         353,369


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         38,129          74,647



            TOTAL. . . . . . . . . . . . . . . . . . .     $2,778,447      $2,681,690

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                           June 30,      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. . . . . . . . . . . . . . . . . . .       572,682          572,492
  Retained Earnings. . . . . . . . . . . . . . . . . .       203,354          186,441
          Total Common Shareholder's Equity. . . . . .       817,062          799,959
  Cumulative Preferred Stock - Subject to
    Mandatory Redemption . . . . . . . . . . . . . . .        25,000           25,000
  Long-term Debt . . . . . . . . . . . . . . . . . . .       946,058          959,786

          TOTAL CAPITALIZATION . . . . . . . . . . . .     1,788,120        1,784,745

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        44,697           42,176

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .        14,000             -
  Short-term Debt. . . . . . . . . . . . . . . . . . .        70,400           52,500
  Accounts Payable - General . . . . . . . . . . . . .        30,259           34,631
  Accounts Payable - Affiliated Companies. . . . . . .        34,819           37,132
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       109,453          141,831
  Interest Accrued . . . . . . . . . . . . . . . . . .        14,387           14,355
  Energy Marketing and Trading Contracts . . . . . . .       112,206           13,682
  Other. . . . . . . . . . . . . . . . . . . . . . . .        27,114           37,197

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       412,638          331,328

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       438,152          442,100

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        46,973           48,710

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        47,867           32,631

CONTINGENCIES (Note 6)

            TOTAL. . . . . . . . . . . . . . . . . . .    $2,778,447       $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>
                                                                 Six Months Ended
                                                                      June 30,
                                                               1999             1998
                                                                   (in thousands)
<S>                                                           <C>             <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 61,977        $ 64,387
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . . .    46,837          45,808
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     2,697           3,959
    Deferred Investment Tax Credits. . . . . . . . . . . . .    (1,737)         (1,775)
    Deferred Collection of Fuel Costs (net). . . . . . . . .     4,252          (5,753)
    Amortization of Deferred Property Taxes. . . . . . . . .    34,406          32,514
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .      (801)          1,709
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    (2,186)            (33)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .   (13,498)        (13,677)
    Prepayments. . . . . . . . . . . . . . . . . . . . . . .    (8,717)         (7,909)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (6,685)            544
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .   (32,378)        (51,022)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .   (10,806)          8,491
        Net Cash Flows From Operating Activities . . . . . .    73,361          77,243

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (46,005)        (57,626)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .       261           2,287
        Net Cash Flows Used For Investing Activities . . . .   (45,744)        (55,339)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .       -           111,075
  Change in Short-term Debt (net). . . . . . . . . . . . . .    17,900         (14,075)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .       -           (81,750)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (43,998)        (41,322)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .      (875)           (437)
        Net Cash Flows Used For Financing Activities . . . .   (26,973)        (26,509)

Net Increase (Decrease) in Cash and Cash Equivalents . . . .       644          (4,605)
Cash and Cash Equivalents at Beginning of Period . . . . . .     7,206          12,626
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  7,850        $  8,021

Supplemental Disclosure:
  Cash paid  for  interest net of capitalized  amounts was $36,491,000 and $37,667,000
  and for income taxes was $14,207,000 and $20,886,000 in 1999 and 1998, respectively.
  Noncash  acquisitions  under  capital  leases were $4,043,000 and $6,060,000 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
                              JUNE 30, 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

       The short-term debt limitation of the Company was increased from $300
   million to $350 million with approval of the Securities and Exchange
   Commission.

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. RATE MATTERS

       The Federal Energy Regulatory Commission (FERC) issued orders 888 and
   889 in April 1996 which required each public utility that owns or
   controls interstate transmission facilities to file an open access
   network and point-to-point transmission tariff that offers services
   comparable to the utility's own uses of its transmission system.  The
   orders also require utilities to functionally unbundle their services,
   by requiring them to use their own tariffs in making off-system and
   third-party sales.  As part of the orders, the FERC issued a pro-forma
   tariff which reflects the Commission's views on the minimum non-price
   terms and conditions for non-discriminatory transmission service.  The
   orders also allow a utility to seek recovery of certain prudently-incurred
   stranded costs that result from unbundled transmission service.

       On July 9, 1996, the AEP System companies filed an Open Access
   Transmission Tariff conforming with the FERC's pro-forma transmission
   tariff, subject to the resolution of certain pricing issues.

<PAGE>
       On July 29, 1999, the FERC approved a draft order which rules on the
   AEP System's pending Open Access Transmission Tariff.  This approved
   order has certain unfavorable pricing issues for which the AEP System has
   30 days to seek rehearing.  If the Commission's order is ultimately
   upheld the Company as a member of the AEP System will have to make
   refunds including interest.  As of June 30, 1999 the Company has not made
   any provisions for its share of a potential refund which is preliminarily
   estimated to be approximately $3 million.

5. OHIO RESTRUCTURING LEGISLATION

       On July 6, 1999, the Governor of the State of Ohio signed The Ohio
   Electric Restructuring Act of 1999.  The Act provides for customer choice
   of electricity supplier and a residential rate reduction of 5% of the
   unbundled generation rate beginning on January 1, 2001.  The Act also
   provides for a five-year transition period to transition from cost based
   rates to market pricing for generation services.  It authorizes the
   Public Utilities Commission of Ohio (PUCO) to address certain major
   transition issues including unbundling of rates and the recovery of
   regulatory assets and other stranded transition costs.

       Retail electric services that will be competitive are defined in the
   Act as electric generation service, aggregation service, and power
   marketing and brokering.  The PUCO has been granted broad oversight
   responsibility under the Act.  The Act requires the PUCO to promulgate
   rules for competitive retail electric generation service.

       The Act further provides Ohio electric utilities with an opportunity
   to recover PUCO approved allowable transition costs through unbundled
   rates paid by customers who do not switch generation suppliers and
   through a wires charges by customers who switch generation suppliers.
   Transition costs can include regulatory assets, impairments of generating
   assets and other stranded costs, employee severance and retraining costs
   and other costs.  Recovery of transition revenues can under certain
   circumstances extend beyond the five-year transition period  but cannot
   continue beyond December 31, 2010.  The Company must file a transition
   plan with the PUCO by January 3, 2000 and the PUCO is required to issue
   a transition order no later than October 31, 2000.

       The Act also provides that the property tax assessment percentage on
   electric generation equipment be lowered from 100% to 25% of value
   effective January 1, 2001.  Electric utilities will also become subject
   to the Ohio Corporate Franchise Tax and municipal income taxes on January
   1, 2002.  The last year for which electric utilities will pay the excise
   tax based on gross receipts is the year ending April 30, 2002.  As of May
   1, 2001 electric distribution companies will be subject to an excise tax
   based on kilowatt-hours sold to Ohio customers.  These changes should put
   the Company's generation operations on an equal level with other
   competitive businesses in Ohio regarding state taxation.

       As discussed in Note 2, "Effects of Regulation and the Zimmer Phase-in
   Plan," of the Notes to Consolidated Financial Statements in the 1998
   Annual Report, the Company defers as regulatory liabilities and assets
   certain revenues and expenses consistent with the regulatory process in
   accordance with Statement of Financial Accounting Standards (SFAS) 71,
   "Accounting for the Effects of Certain Types of Regulation."  At June 30,
   1999, the amount of regulatory assets recorded on the books applicable
   to the generating business is estimated to be $275 million before related
   tax effects.  Whether the Company will have any additional stranded
   transition costs related to an economic impairment of its generating
   assets is dependent on several factors including the assumed future
   market price for electricity.  The Company intends to seek recovery in
   its transition filing of all regulatory assets and any other stranded
   transition costs which may be identified. At this time management is
   unable to predict the outcome of the regulatory process or its impact on
   results of operations, cash flows or financial condition.  Therefore, the
   Company will not be discontinuing application of SFAS 71 until the
   regulatory process is completed.

       Upon discontinuance of the application of SFAS 71 the Company will
   have to write off its generation-related regulatory assets and record any
   asset impairments in accordance with SFAS 121 "Accounting for the
   Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed
   Of."  Absent the determination in the regulatory process of transition
   revenues and other pertinent information, it is not possible at this time
   to determine if any of the Company's plants are impaired in accordance
   with SFAS 121.  Should the Company be granted recovery of its regulatory
   assets and/or any economic asset impairments it can record an offsetting
   regulatory asset.  Should the PUCO not approve the Company's request for
   recovery of its generation-related regulatory assets and/or other
   stranded transition costs it would have an adverse impact on future
   results of operations and possibly financial condition.  The Company does
   not expect to be able to determine the impact of the legislation on its
   financial statements until the regulatory process is complete.  The PUCO
   is required to complete its regulatory process no later than October 31,
   2000.

6. 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 June 30, 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 is seeking refunds
   through litigation of all amounts paid plus interest.

<PAGE>
       In order to resolve this issue, the Company filed suit against the
   United States in the United States (U.S.) 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.

   Air Quality

       As discussed in Note 3 of the Notes to Consolidated Financial
   Statements in the 1998 Annual Report, the U.S. Environmental Protection
   Agency (Federal EPA) issued final rules which require reductions in
   nitrogen oxides (NOx) emissions in 22 eastern states, including the
   states in which the generating plants of the Company and its AEP System
   affiliates are located.  The final rules were to be implemented through
   state implementation plans (SIPs).  SIPs are a procedural method used by
   each state to comply with Federal EPA rules.  The NOx SIP Call rule
   requires submission of revised SIPs by September 30, 1999.  A number of
   utilities, including the Company and its AEP System affiliates, filed
   petitions seeking a review of the final rule in the U.S. Court of Appeals
   for the District of Columbia Circuit (Appeals Court).  On May 25, 1999,
   the Appeals Court ordered an indefinite stay of the September 30, 1999
   deadline for submission of SIP revisions pending a further order of the
   court while arguments regarding the SIP Call rule are considered.

       On April 30, 1999, Federal EPA took final action with respect to
   petitions filed by eight northeastern states pursuant to Section 126 of
   the Clean Air Act.  Federal EPA approved portions of the states'
   petitions triggering emission reductions that are substantially the same
   as those that would otherwise have been required by the NOx SIP Call.
   The imposition of these NOx reduction requirements on AEP System
   generating units would be approximately equivalent to the reductions
   contemplated by the stayed SIP Call rule.  On May 28, and June 1, 1999,
   the Utility Air Regulatory Group and the Midwest Ozone Group,
   respectively, each filed a petition in the Appeals Court seeking review
   of Federal EPA's approval of portions of the northeastern states'
   petitions.  In the second quarter of 1999, three additional northeastern
   states filed Section 126 petitions with Federal EPA similar to those
   filed by the eight northeastern states.

       Preliminary estimates indicate that NOx compliance could result in
   required capital expenditures of approximately $175 million for the
   Company.  Compliance costs cannot be estimated with certainty and the
   actual costs incurred to comply could be significantly different from
   this preliminary estimate depending upon the compliance alternatives
   selected to achieve reductions in NOx emissions.  Unless such costs are
   recovered from customers or reflected in the future market price of
   electricity, they will have a material adverse effect on future results
   of operations, cash flows and possibly financial condition.

   Other

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


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

                SECOND QUARTER 1999 vs. SECOND QUARTER 1998
                                    AND
                  YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998

     Net income decreased $4.2 million or 11% in the second quarter and $2.4
million or 4% in the year-to-date period primarily due to increased operating
expenses.
       Income statement line items which changed significantly were:
                                    Increase (Decrease)
                            Second Quarter        Year-to-Date
                          (in millions)   %    (in millions)   %

Operating Revenues. . . . .   $ 3.2       1        $15.8       3
Fuel Expense. . . . . . . .     2.3       5          1.2       1
Purchased Power Expense . .     0.5       1          7.8       7
Maintenance Expense . . . .     3.5      23          3.1      11
Taxes Other Than Federal
 Income Taxes . . . . . . .     2.4       9          3.5       6
Federal Income Taxes. . . .    (3.2)    (14)        (0.1)      -

   Operating revenues increased in both the second quarter and the year-to-date
period due predominantly to increased retail sales.  Retail revenues and
sales increased 4% and 3%, respectively, in the second quarter and 5% in the
year-to-date period due to customer growth and the effect of colder winter
weather on residential and commercial usage in the year-to-date period.
   Fuel expense increased in the second quarter due to the operation of the
fuel clause adjustment mechanism as prior period deferrals of underrecovered
fuel costs were amortized to expense in the current period concurrent with
rate recovery.
   The increase in purchased power expense in the year-to-date period 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.

<PAGE>
   Maintenance expense increased primarily due to scheduled power plant
maintenance outages of the Zimmer Plant and one unit of the Conesville Plant
in 1999.
   The increase in taxes other than federal income taxes was primarily due
to higher property tax rates in 1999 and the effect of a favorable property
tax accrual adjustment recorded in May 1998.
   Federal income taxes attributable to operations decreased in the second
quarter primarily as a result of a decrease in pre-tax operating income.

<PAGE>
<PAGE>
<TABLE>
              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                          Three Months Ended           Six Months Ended
                                               June 30,                    June 30,
                                           1999        1998            1999        1998
                                                         (in thousands)
<S>                                      <C>         <C>            <C>           <C>
OPERATING REVENUES . . . . . . . . . . . $336,553    $348,271       $  670,666    $676,739

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   42,123      37,875           83,923      82,754
  Purchased Power. . . . . . . . . . . .   67,510      86,504          129,825     144,663
  Other Operation. . . . . . . . . . . .  115,258      82,850          206,833     159,283
  Maintenance. . . . . . . . . . . . . .   24,621      33,259           55,823      60,337
  Depreciation and Amortization. . . . .   37,495      36,234           74,480      72,027
  Taxes Other Than Federal Income Taxes.   17,256      16,105           36,285      32,497
  Federal Income Taxes . . . . . . . . .    5,324      13,250           17,693      31,616

          TOTAL OPERATING EXPENSES . . .  309,587     306,077          604,862     583,177

OPERATING INCOME . . . . . . . . . . . .   26,966      42,194           65,804      93,562
NONOPERATING INCOME. . . . . . . . . . .    1,556       3,585            3,291       2,595
INCOME BEFORE INTEREST CHARGES . . . . .   28,522      45,779           69,095      96,157
INTEREST CHARGES . . . . . . . . . . . .   18,777      17,243           39,280      33,877
NET INCOME . . . . . . . . . . . . . . .    9,745      28,536           29,815      62,280
PREFERRED STOCK DIVIDEND REQUIREMENTS. .    1,215       1,202            2,429       2,419
EARNINGS APPLICABLE TO COMMON STOCK. . . $  8,530    $ 27,334       $   27,386    $ 59,861


               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended          Six Months Ended
                                               June 30,                   June 30,
                                           1999        1998           1999        1998
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $243,346    $281,975       $253,154    $278,814
NET INCOME . . . . . . . . . . . . . . .    9,745      28,536         29,815      62,280
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   28,664      29,366         57,328      58,732
    Cumulative Preferred Stock . . . . .    1,182       1,183          2,364       2,367
  Capital Stock Expense. . . . . . . . .       33          19             65          52

BALANCE AT END OF PERIOD . . . . . . . . $223,212    $279,943       $223,212    $279,943

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>
                                                            June 30,      December 31,
                                                              1999            1998
                                                                 (in thousands)
ASSETS
<S>                                                        <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,583,294      $2,565,041
  Transmission . . . . . . . . . . . . . . . . . . . .        919,595         913,495
  Distribution . . . . . . . . . . . . . . . . . . . .        785,634         768,888
  General (including nuclear fuel) . . . . . . . . . .        232,486         228,013
  Construction Work in Progress. . . . . . . . . . . .        167,441         156,411
          Total Electric Utility Plant . . . . . . . .      4,688,450       4,631,848
  Accumulated Depreciation and Amortization. . . . . .      2,143,088       2,081,355

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,545,362       2,550,493



NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
  FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . .        688,793         648,307


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        214,515         197,368



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         20,839          12,465
  Accounts Receivable (net). . . . . . . . . . . . . .        141,220         130,746
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         36,466          20,857
  Materials and Supplies . . . . . . . . . . . . . . .         85,941          78,009
  Accrued Utility Revenues . . . . . . . . . . . . . .         31,354          37,277
  Energy Marketing and Trading Contracts . . . . . . .        121,939          14,105
  Prepayments. . . . . . . . . . . . . . . . . . . . .          5,880           4,848

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        443,639         298,307



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        525,631         421,475



DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         31,064          32,573



            TOTAL. . . . . . . . . . . . . . . . . . .     $4,449,004      $4,148,523

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                           June 30,       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. . . . . . . . . . . . . . . . . . .       732,672          732,605
  Retained Earnings. . . . . . . . . . . . . . . . . .       223,212          253,154
          Total Common Shareholder's Equity. . . . . .     1,012,468        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 . . . . . . . . . . . . . . . . . . .       982,604        1,140,789

          TOTAL CAPITALIZATION . . . . . . . . . . . .     2,072,783        2,260,850

OTHER NONCURRENT LIABILITIES:
  Nuclear Decommissioning. . . . . . . . . . . . . . .       480,938          445,934
  Other. . . . . . . . . . . . . . . . . . . . . . . .       247,389          240,320

          TOTAL OTHER NONCURRENT LIABILITIES . . . . .       728,327          686,254

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .       133,000           35,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .       269,180          108,700
  Accounts Payable - General . . . . . . . . . . . . .        54,488           53,187
  Accounts Payable - Affiliated Companies. . . . . . .        29,114           37,647
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .        11,299           35,161
  Interest Accrued . . . . . . . . . . . . . . . . . .        14,355           15,279
  Revenue Refunds Accrued. . . . . . . . . . . . . . .        55,000              -
  Obligations Under Capital Leases . . . . . . . . . .        10,744            9,667
  Energy Marketing and Trading Contracts . . . . . . .       122,541           15,228
  Dividends Declared . . . . . . . . . . . . . . . . .        29,846            1,183
  Other. . . . . . . . . . . . . . . . . . . . . . . .        76,093           70,882

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       805,660          381,934

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       573,752          559,288

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       125,983          129,779

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .        86,859           88,712

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        55,640           41,706

COMMITMENTS AND CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .    $4,449,004       $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>
                                                                  Six Months Ended
                                                                      June 30,
                                                                1999            1998
                                                                   (in thousands)
<S>                                                          <C>              <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . $  29,815        $ 62,280
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    76,431          74,126
    Amortization of Incremental Nuclear
      Refueling Outage Expenses (net). . . . . . . . . . . .     4,695           8,518
    Unrecovered Fuel and Purchased Power . . . . . . . . . .   (63,922)        (34,369)
    Deferred Nuclear Outage Costs (net). . . . . . . . . . .   (60,000)           -
    Deferred Federal Income Taxes. . . . . . . . . . . . . .    23,448           7,839
    Deferred Investment Tax Credits. . . . . . . . . . . . .    (3,796)         (3,818)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .   (10,474)        (61,320)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .   (23,541)        (10,343)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     5,923         (11,384)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (7,232)         57,979
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .   (23,862)        (12,041)
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . .    55,000            -
    Dividends Declared . . . . . . . . . . . . . . . . . . .    28,663            -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .   (25,103)         (8,581)
        Net Cash Flows From Operating Activities . . . . . .     6,045          68,886

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (63,316)        (61,203)
  Proceeds from Sale of Property . . . . . . . . . . . . . .     1,198           1,391
        Net Cash Flows Used for Investing Activities . . . .   (62,118)        (59,812)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .      -            122,222
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (65,000)        (35,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .   160,480          (8,800)
  Retirement of Cumulative Preferred Stock . . . . . . . . .        (5)            (39)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (28,664)        (58,732)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .    (2,364)         (2,368)
        Net Cash Flows From Financing Activities . . . . . .    64,447          17,283

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     8,374          26,357
Cash and Cash Equivalents at Beginning of Period . . . . . .    12,465           5,860
Cash and Cash Equivalents at End of Period . . . . . . . . . $  20,839       $  32,217

Supplemental Disclosure:
  Cash paid for interest  net of capitalized  amounts was  $38,775,000 and $32,651,000
  and for income taxes was $19,217,000 and $15,054,000 in 1999 and 1998, respectively.
  Noncash acquisitions  under capital  leases were $6,901,000  and $18,801,000 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
                          JUNE 30, 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 ACTIVITIES

       During the first six months of 1999, the Company reacquired
   the following first mortgage bonds for $65 million:

                                             Principal
                                               Amount
        % Rate        Due Date               Reacquired
                                           (in thousands)
        6.80          July 1, 2003            $20,000
        6.55          October 1, 2003          20,000
        6.55          March 1, 2004            25,000

       In July 1999 the Company issued $150 million of 6-7/8%
   senior unsecured notes due 2004.

       The short-term debt limitation of the Company was increased
   from $300 million to $500 million with approval of the
   Securities and Exchange Commission.

       During the first six months of 1999, the Company issued
   $160 million of short-term debt.

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.

<PAGE>
4. RATE MATTERS

       The Federal Energy Regulatory Commission (FERC) issued
   orders 888 and 889 in April 1996 which required each public
   utility that owns or controls interstate transmission
   facilities to file an open access network and point-to-point
   transmission tariff that offers services comparable to the
   utility's own uses of its transmission system.  The orders also
   require utilities to functionally unbundle their services, by
   requiring them to use their own tariffs in making off-system
   and third-party sales.  As part of the orders, the FERC issued
   a pro-forma tariff which reflects the Commission's views on the
   minimum non-price terms and conditions for non-discriminatory
   transmission service.  The orders also allow a utility to seek
   recovery of certain prudently-incurred stranded costs that
   result from unbundled transmission service.

       On July 9, 1996, the AEP System companies filed an Open
   Access Transmission Tariff conforming with the FERC's pro-forma
   transmission tariff, subject to the resolution of certain
   pricing issues.

       On July 29, 1999, the FERC approved a draft order which
   rules on the AEP System's pending Open Access Transmission
   Tariff.  This approved order has certain unfavorable pricing
   issues for which the AEP System has 30 days to seek rehearing.
   If the Commission's order is ultimately upheld the Company as
   a member of the AEP System will have to make refunds including
   interest.  As of June 30, 1999 the Company has not made any
   provisions for its share of a potential refund which is
   preliminarily estimated to be approximately $4 million.

5. 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 June 30,
   1999 would reduce earnings by approximately $66 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 is seeking refunds
   through litigation of all amounts paid plus interest.

       In order to resolve this issue, the Company filed suit
   against the United States in the U.S. District Court for the
   Southern District of Ohio in 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.

   Air Quality

       As discussed in Note 3 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the U.S.
   Environmental Protection Agency (Federal EPA) issued final
   rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which
   the generating plants of the Company and its AEP System
   affiliates are located.  The final rules were to be implemented
   through state implementation plans (SIPs).  SIPs are a
   procedural method used by each state to comply with Federal EPA
   rules.  The NOx SIP Call rule requires submission of revised
   SIPs by September 30, 1999.  A number of utilities, including
   the Company and its AEP System affiliates, filed petitions
   seeking a review of the final rule in the U.S. Court of Appeals
   for the District of Columbia Circuit (Appeals Court).  On May
   25, 1999, the Appeals Court ordered an indefinite stay of the
   September 30, 1999 deadline for submission of SIP revisions
   pending a further order of the court while arguments regarding
   the SIP Call rule are considered.

       On April 30, 1999, Federal EPA took final action with
   respect to petitions filed by eight northeastern states
   pursuant to Section 126 of the Clean Air Act.  Federal EPA
   approved portions of the states' petitions triggering emission
   reductions that are substantially the same as those that would
   otherwise have been required by the NOx SIP Call.  The
   imposition of these NOx reduction requirements on AEP System
   generating units would be approximately equivalent to the
   reductions contemplated by the stayed SIP Call rule.  On May
   28, and June 1, 1999, the Utility Air Regulatory Group and the
   Midwest Ozone Group, respectively, each filed a petition in the
   Appeals Court seeking review of Federal EPA's approval of
   portions of the northeastern states' petitions.  In the second
   quarter of 1999, three additional northeastern states filed
   Section 126 petitions with Federal EPA similar to those filed
   by the eight northeastern states.

       Preliminary estimates indicate that NOx compliance could
   result in required capital expenditures of approximately $215
   million for the Company.  Compliance costs cannot be estimated
   with certainty and the actual costs incurred to comply could
   be significantly different from this preliminary estimate
   depending upon the compliance alternatives selected to achieve
   reductions in NOx emissions.  Unless such costs are recovered
   from customers through regulated rates and/or reflected in the
   future market price of electricity if generation is
   deregulated, they will have a material adverse effect on future
   results of operations, cash flows and possibly financial
   condition.

   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.
   In 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 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.

       On June 24, 1999, the Boards of Directors of American
   Electric Power Company, Inc. and the Company both approved a
   plan to restart the Cook Plant.  Unit 2 is scheduled to return
   to service in April 2000 and Unit 1 is to return to service in
   September 2000.  This approval follows a comprehensive systems
   readiness review of all operating systems at the Cook Plant.
   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.

       Management intends to replace the steam generator for Unit
   1 before the unit is returned to service.  Costs associated
   with the steam generator replacement are estimated to be
   approximately $165 million, which will be accounted for as a
   capital investment unrelated to the restart.  At June 30, 1999,
   $70 million has been spent on the steam generator replacement.

       The cost of electricity supplied to retail customers
   increased due to the outage of the two Cook Plant nuclear units
   since higher cost coal-fired generation and coal based
   purchased power is being substituted for the unavailable low
   cost nuclear generation.  Actual replacement energy fuel costs
   that exceeded the costs reflected in billings have been
   recorded as a regulatory asset under the Indiana and Michigan
   retail jurisdictional fuel cost recovery mechanisms.  At June
   30, 1999, the regulatory asset was $129 million.

       On March 30, 1999 the Indiana Utility Regulatory Commission
   (IURC) approved a settlement agreement that resolves all
   matters related to the recovery of replacement energy fuel
   costs and all outage/restart 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' bills; the deferral of
   unrecovered fuel revenues accrued between September 9, 1997 and
   December 31, 1999, including the $52.3 million revenue portion
   of the $55 million billing credit; the deferral of up to $150
   million of incremental operation and maintenance costs in 1999
   for Cook Plant above the amount included in base rates; the
   amortization of the deferred 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 applied to
   customers' bills  during the months of July, August and
   September 1999.

       In June 1999 the Company announced that a settlement
   agreement for two open Michigan power supply cost recovery
   reconciliation cases had been reached with the staff of the
   Michigan Public Service Commission (MPSC).  The proposed
   settlement agreement would freeze rates and power supply costs
   for five years, allow for the amortization of deferred power
   supply cost for 1997, 1998 and 1999 over five years, allow for
   the deferral and amortization of non-fuel nuclear operation and
   maintenance expenses over five years and resolve all issues
   related to the Cook Plant extended outage.  At a hearing on
   June 30, 1999, the MPSC granted a continuance to the one
   intervenor who opposed the approval of the settlement
   agreement.  A hearing has been scheduled for August 13, 1999.

       Expenditures for the restart of the Cook units are
   estimated to total approximately $574 million and will be
   accounted for primarily as current period operation and
   maintenance expense in 1999 and 2000.  Through June 30, 1999,
   $192 million has been spent, of which $108 million was incurred
   in the first half of 1999.  Pursuant to the Indiana settlement
   agreement $60 million of incremental operation and maintenance
   costs were deferred through June 30, 1999.  The Indiana
   jurisdiction deferral is limited to up to $150 million of
   incremental restart costs incurred in 1999.  The pending
   Michigan settlement limits deferrals to $50 million of non-fuel
   operation and maintenance costs.

       The costs of the extended outage and restart efforts will
   have a material adverse effect on future results of operations,
   cash flows, and possibly financial condition through 2003.
   Management believes that the Cook units will be successfully
   returned to service by April and September 2000, however, if
   for some unknown reason the units are not returned to service
   or their return is delayed significantly it would have an even
   greater adverse effect on future results of operations, cash
   flows and financial condition.

   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

           SECOND QUARTER 1999 vs. SECOND QUARTER 1998
                               AND
             YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998

RESULTS OF OPERATIONS
   Net income decreased $18.8 million or 66% in the second quarter
and $32.5 million or 52% for the year-to-date period due primarily
to increased operation 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)
                            Second Quarter        Year-to-Date
                          (in millions)   %    (in millions)   %

Operating Revenues. . . .     $(11.7)    (3)       $ (6.1)    (1)
Fuel Expense. . . . . . .        4.2     11           1.2      1
Purchased Power Expense .      (19.0)   (22)        (14.8)   (10)
Other Operation Expense .       32.4     39          47.6     30
Maintenance Expense . . .       (8.6)   (26)         (4.5)    (7)
Taxes Other Than
 Federal Income Taxes . .        1.2      7           3.8     12
Federal Income Taxes. . .       (7.9)   (60)        (13.9)   (44)
Interest Charges. . . . .        1.5      9           5.4     16

   Operating revenues decreased in both the second quarter and the
year-to-date period due primarily to a decrease in retail revenues
reflecting the effect of an Indiana settlement agreement on fuel
recovery billings in the Company's Indiana retail jurisdiction.
Under the terms of the settlement agreement, approved by the
Indiana commission in March 1999, the fuel recovery rate was
reduced and fixed through March 1, 2004.  The unrecovered Cook
replacement power and restart costs were deferred for future
amortization.
   Fuel expense increased in the second quarter due to an increase
in generation reflecting increased availability of the Company's
coal fired generating units in 1999.
   The decrease in purchased power expense resulted from decreased
purchases reflecting the increased generating plant availability.
   Other operation expense increased due to increased nuclear
engineering and contract employee costs during the extended Cook
shutdown and restart efforts.
<PAGE>
   The deferral in 1999 of maintenance costs
during the extended shutdown of the Cook Plant under the terms of the Indiana
settlement agreement accounted for the decrease in maintenance
expense.
   Increases in real and personal property, gross receipts and
single business taxes accounted for the increases in taxes other
than federal income taxes.
   Federal income taxes attributable to operations decreased in
both periods as a result of a decrease in pre-tax operating income.
   Interest expense increased in the second quarter due to an
increase in short-term borrowing to fund the expenditures for the
Cook Plant restart effort.  In the year-to-date period interest
expense increased due to increased long-term debt interest expense
reflecting higher outstanding balances, the accrual of interest for
revenue refunds ordered by the Indiana commission as part of the
settlement agreement and the increase in short-term borrowings.
FINANCIAL CONDITION
   Total plant and property additions including capital leases for
the year-to-date period were $71 million.
   During the first six months of 1999 the Company redeemed $65
million principal amount of first mortgage bonds with interest
rates from 6.55% to 6.80%.  Short-term debt outstanding increased
by $160 million from year-end balances.
   In July 1999 the Company issued $150 million of 6-7/8% senior
unsecured notes due 2004.
   The short-term debt limitation of the Company was increased
from $300 million to $500 million with the approval of the
Securities and Exchange Commission.
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
(U.S.) 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 U.S. 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.
On May 20, 1999, the other utility appealed this decision to the
U.S. Court of Appeals for the Federal Circuit.  I&M's case has been
stayed pending final resolution of the other utility's appeal.
Cook Nuclear Plant Shutdown
   As discussed in MDA 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.  In 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 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.
   On June 24, 1999, the Boards of Directors of American Electric
Power Company, Inc. and the Company both approved a plan to restart
the Cook Plant.  Unit 2 is scheduled to return to service in April
2000 and Unit 1 is to return to service in September 2000.  This
approval follows a comprehensive systems readiness review of all
operating systems at the Cook Plant.  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.
   Management intends to replace the steam generator for Unit 1
before the unit is returned to service.  Costs associated with the
steam generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart.  At June 30, 1999, $70 million has been
spent on the steam generator replacement.
   The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal based purchased power is being
substituted for the unavailable low cost nuclear generation.
Actual replacement energy fuel costs that exceeded the estimated
costs reflected in billings have been recorded as a regulatory
asset under the Indiana and Michigan retail jurisdictional fuel
cost recovery mechanisms.  At June 30, 1999, the regulatory asset
was $129 million.
   On March 30, 1999 the Indiana Utility Regulatory Commission
(IURC) approved a settlement agreement that resolves all matters
related to the recovery of replacement energy fuel costs and all
outage/restart 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'
bills; the deferral of any unrecovered fuel revenues accrued
between September 9, 1997 and December 31, 1999, including the
$52.3 million revenue portion of the $55 million billing credit;
the deferral of up to $150 million of incremental operation and
maintenance costs in 1999 for Cook Plant above the amount included
in base rates; the amortization of the deferred 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 applied to customers'
bills during the months of July, August and September 1999.

<PAGE>
   In June 1999 the Company announced that a settlement agreement
for two open Michigan power supply cost recovery reconciliation
cases had been reached with the staff of the Michigan Public
Service Commission (MPSC).  The proposed settlement agreement would
freeze rates and power supply costs for five years, allow for the
amortization of deferred power supply cost for 1997, 1998 and 1999
over five years, allow for the deferral and amortization of non-fuel nuclear
operation and maintenance expenses over five years and
resolve all issues related to the Cook Plant extended outage.  At
a hearing on June 30, 1999, the MPSC granted a continuance to the
one intervenor who opposed the approval of the settlement
agreement.  A hearing has been scheduled for August 13, 1999.
   Expenditures for the restart of the Cook units are estimated
to total approximately $574 million and will be accounted for
primarily as current period operation and maintenance expense in
1999 and 2000.  Through June 30, 1999, $192 million has been spent,
of which $108 million was incurred in the first half of 1999.
Pursuant to the Indiana settlement agreement $60 million of
incremental operation and maintenance costs were deferred through
June 30, 1999.  The Indiana jurisdiction deferral is limited to up
to $150 million of incremental restart costs incurred in 1999.  The
pending Michigan settlement limits deferrals to $50 million of non-fuel
operation and maintenance costs.
   The costs of the extended outage and restart efforts will have
a material adverse effect on results of operations, cash flows, and
possibly financial condition through 2003.  Management believes
that the Cook units will be successfully returned to service by
April and September 2000, however, if for some unknown reason the
units are not returned to service or their return is delayed
significantly it would have an even greater adverse effect on
results of operations, cash flows and financial condition.
Air Quality
   As discussed in MDA in the 1998 Annual Report, the U.S.
Environmental Protection Agency (Federal EPA) issued final rules
which require reductions in nitrogen oxides (NOx) emissions in 22
eastern states, including the states in which the generating plants
of the Company and its AEP System affiliates are located.  The
final rules were to be implemented through state implementation
plans (SIPs).  SIPs are a procedural method used by each state to
comply with Federal EPA rules.  The NOx SIP Call rule requires
submission of revised SIPs by September 30, 1999.  A number of
utilities, including the Company and its AEP System affiliates,
filed petitions seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit (Appeals
Court).  On May 25, 1999, the Appeals Court ordered an indefinite
stay of the September 30, 1999 deadline for submission of SIP
revisions pending a further order of the court while arguments
regarding the SIP Call rule are considered.
   On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act.  Federal EPA approved portions of the
states' petitions triggering emission reductions that are
substantially the same as those that would otherwise have been
required by the NOx SIP Call.  The imposition of these NOx
reduction requirements on AEP System generating units would be
approximately equivalent to the reductions contemplated by the
stayed SIP Call rule.  On May 28, and June 1, 1999, the Utility Air
Regulatory Group and the Midwest Ozone Group, respectively, each
filed a petition in the Appeals Court seeking review of Federal
EPA's approval of portions of the northeastern states' petitions.
In the second quarter of 1999, three additional northeastern states
filed Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
   Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $215 million for
the Company.  Compliance costs cannot be estimated with certainty
and the actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions.  Unless such costs are recovered from customers through
regulated rates and/or reflected in the future market price of
electricity if generation is deregulated, they will have a material
adverse effect on future results of operations, cash flows and
possibly financial condition.

<PAGE>
Market Risks
   The Company has certain market risks inherent in its business
activities 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 June 30, 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,
has submitted information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reported summary information to the US DOE
regarding the Y2K readiness of electric utilities.  The fourth and
final NERC report, dated August 3, 1999 and entitled: Preparing the
Electric Power Systems of North America for Transition to the Year
2000 - A Status Report and Work Plan, Second Quarter 1999, states
that: "Mission-critical component testing indicates 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 caused 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.
   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.
   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 the Company's progress toward
becoming ready for the Y2K as of June 30, 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    2/24/1998        100%      5/31/1998       100%
of 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     100%
replacing or retiring                    100%
those mission critical and
high priority digital-based
systems with problems                    Client
processing dates in the                  Server:
Year 2000. Testing these                 99%*
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.

*The Company is upgrading a meteorological reporting system used at the Cook
Plant, a mission critical IT system, for Y2K readiness and it is anticipated
that the upgrade should be completed by December 15, 1999.

Costs to Address the Company's Year 2000 Issues - Through June 30,
1999, the Company has spent $6 million on the Y2K project and,
estimates spending an additional $2 million to $4 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.  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.

<PAGE>
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 Y2K contingency plan and
submitted it to the East Central Area Reliability Council as part
of NERC's review of regional and individual electric utility
contingency plans in 1999.  In addition, the Company is
establishing 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.
   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, in order to place
   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        Six Months Ended
                                                 June 30,                 June 30,
                                             1999        1998        1999         1998
                                                          (in thousands)
<S>                                        <C>         <C>         <C>          <C>
OPERATING REVENUES . . . . . . . . . . . . $86,231     $84,021     $176,972     $171,366

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . .  22,284      18,184       41,975       40,485
  Purchased Power. . . . . . . . . . . . .  25,920      27,119       50,347       48,330
  Other Operation. . . . . . . . . . . . .  11,768      11,992       24,119       22,986
  Maintenance. . . . . . . . . . . . . . .   5,047       7,258        9,838       16,424
  Depreciation and Amortization. . . . . .   7,287       6,978       14,477       13,888
  Taxes Other Than Federal Income Taxes. .   2,682       2,260        5,216        4,752
  Federal Income Taxes . . . . . . . . . .   1,010         599        5,407        2,779

         TOTAL OPERATING EXPENSES. . . . .  75,998      74,390      151,379      149,644

OPERATING INCOME . . . . . . . . . . . . .  10,233       9,631       25,593       21,722

NONOPERATING LOSS. . . . . . . . . . . . .     (41)        (93)        (155)        (164)

INCOME BEFORE INTEREST CHARGES . . . . . .  10,192       9,538       25,438       21,558

INTEREST CHARGES . . . . . . . . . . . . .   7,197       7,125       14,234       14,128

NET INCOME . . . . . . . . . . . . . . . . $ 2,995     $ 2,413     $ 11,204     $  7,430




                      STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended        Six Months Ended
                                                 June 30,                 June 30,
                                             1999        1998        1999         1998
                                                          (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . $72,218     $76,018      $71,452      $78,076

NET INCOME . . . . . . . . . . . . . . . .   2,995       2,413       11,204        7,430

CASH DIVIDENDS DECLARED. . . . . . . . . .   7,443       7,075       14,886       14,150

BALANCE AT END OF PERIOD . . . . . . . . . $67,770     $71,356      $67,770      $71,356



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>
                                                          June 30,        December 31,
                                                            1999              1998
                                                                (in thousands)
ASSETS
<S>                                                      <C>               <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .   $  267,658        $  267,201
  Transmission . . . . . . . . . . . . . . . . . . . .      340,617           326,989
  Distribution . . . . . . . . . . . . . . . . . . . .      358,349           351,407
  General. . . . . . . . . . . . . . . . . . . . . . .       66,452            68,038
  Construction Work in Progress. . . . . . . . . . . .       22,083            30,076
          Total Electric Utility Plant . . . . . . . .    1,055,159         1,043,711
  Accumulated Depreciation and Amortization. . . . . .      326,751           315,546

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      728,408           728,165


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .       18,376            12,078


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .        2,436             1,935
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .       18,560            23,295
    Affiliated Companies . . . . . . . . . . . . . . .       14,087             8,797
    Miscellaneous. . . . . . . . . . . . . . . . . . .        3,268             4,019
    Allowance for Uncollectible Accounts . . . . . . .       (1,094)             (848)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .        9,358             7,888
  Materials and Supplies . . . . . . . . . . . . . . .       16,570            13,652
  Accrued Utility Revenues . . . . . . . . . . . . . .       13,052            13,560
  Energy Marketing and Trading Contracts . . . . . . .       45,027             4,726
  Prepayments. . . . . . . . . . . . . . . . . . . . .        1,954             1,657

          TOTAL CURRENT ASSETS . . . . . . . . . . . .      123,218            78,681


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .       92,327            92,447


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .        8,560            10,476


            TOTAL. . . . . . . . . . . . . . . . . . .   $  970,889        $  921,847

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                            June 30,      December 31,
                                                              1999            1998
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                         <C>             <C>
CAPITALIZATION:
  Common Stock - $50 Par Value:
    Authorized -  2,000,000 Shares
    Outstanding - 1,009,000 Shares . . . . . . . . . .      $ 50,450        $ 50,450
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       158,750         148,750
  Retained Earnings. . . . . . . . . . . . . . . . . .        67,770          71,452
          Total Common Shareholder's Equity. . . . . .       276,970         270,652
  Long-term Debt . . . . . . . . . . . . . . . . . . .       271,228         308,838

          TOTAL CAPITALIZATION . . . . . . . . . . . .       548,198         579,490

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        24,745          26,827

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .        60,000          60,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .        56,350          20,350
  Accounts Payable - General . . . . . . . . . . . . .         9,363          12,917
  Accounts Payable - Affiliated Companies. . . . . . .        14,166          11,814
  Customer Deposits. . . . . . . . . . . . . . . . . .         4,006           4,038
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         9,244           7,256
  Interest Accrued . . . . . . . . . . . . . . . . . .         5,522           6,241
  Energy Marketing and Trading Contracts . . . . . . .        45,245           5,089
  Other. . . . . . . . . . . . . . . . . . . . . . . .        13,476          13,612

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       217,372         141,317

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       159,541         158,706

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        13,599          14,200

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .         7,434           1,307

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .      $970,889        $921,847

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                         STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                 Six Months Ended
                                                                     June 30,
                                                                1999          1998
                                                                  (in thousands)
<S>                                                           <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 11,204      $  7,430
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    14,480        13,894
    Deferred Federal Income Taxes. . . . . . . . . . . . . .       912           368
    Deferred Investment Tax Credits. . . . . . . . . . . . .      (601)         (610)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .       442        (2,792)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    (4,388)       (1,234)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .       508         2,409
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (1,202)       (2,281)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .     1,988          (902)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     1,258           811
        Net Cash Flows From Operating Activities . . . . . .    24,601        17,093

INVESTING ACTIVITIES - Construction Expenditures . . . . . .   (17,402)      (17,705)

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .    10,000        10,000
  Change in Short-term Debt (net). . . . . . . . . . . . . .    36,000         6,600
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (37,812)       (2,203)
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .   (14,886)      (14,150)
        Net Cash Flows From (Used For) Financing Activities.    (6,698)          247

Net Increase (Decrease) in Cash and Cash Equivalents . . . .       501          (365)
Cash and Cash Equivalents at Beginning of Period . . . . . .     1,935         1,381
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  2,436      $  1,016

Supplemental Disclosure:
  Cash paid for interest  net of capitalized amounts was $14,748,000 and $13,982,000
  and for income taxes was $3,631,000 and $4,538,000 in 1999 and 1998, respectively.
  Noncash acquisitions  under capital leases were $1,150,000 and  $2,960,000 in 1999
  and 1998, respectively.


See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
                          KENTUCKY POWER COMPANY
                       NOTES TO FINANCIAL STATEMENTS
                               JUNE 30, 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 redeemed a $25 million term loan note with
   a rate of 6.42% and in May 1999 the Company redeemed the principal amount
   of $12,797,000 of the 7.90% Series First Mortgage Bonds.

       In June 1999 the Company received a $10 million cash capital
   contribution from its parent which was credited to paid-in capital.

       During the first six months of 1999, the Company issued $36 million
   of short-term debt.

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. RATE MATTERS

       The Federal Energy Regulatory Commission (FERC) issued orders 888 and
   889 in April 1996 which required each public utility that owns or
   controls interstate transmission facilities to file an open access
   network and point-to-point transmission tariff that offers services
   comparable to the utility's own uses of its transmission system.  The
   orders also require utilities to functionally unbundle their services,
   by requiring them to use their own tariffs in making off-system and
   third-party sales.  As part of the orders, the FERC issued a pro-forma
   tariff which reflects the Commission's views on the minimum non-price
   terms and conditions for non-discriminatory transmission service.  The
   orders also allow a utility to seek recovery of certain prudently-incurred
   stranded costs that result from unbundled transmission service.

<PAGE>
       On July 9, 1996, the AEP System companies filed an Open Access
   Transmission Tariff conforming with the FERC's pro-forma transmission
   tariff, subject to the resolution of certain pricing issues.

       On July 29, 1999, the FERC approved a draft order which rules on the
   AEP System's pending Open Access Transmission Tariff.  This approved
   order has certain unfavorable pricing issues for which the AEP System has
   30 days to seek rehearing.  If the Commission's order is ultimately
   upheld the Company as a member of the AEP System will have to make
   refunds including interest.  As of June 30, 1999 the Company has not made
   any provisions for its share of a potential refund which is preliminarily
   estimated to be approximately $1 million.

5. CONTINGENCIES

   Litigation

       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 June 30, 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 is seeking refunds through
   litigation of all amounts paid plus interest.

       In order to resolve this issue, the Company filed suit against the
   United States in the U.S. District Court for the Southern District of
   Ohio in 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.

   Air Quality

       As discussed in Note 3 of the Notes to Financial Statements in the
   1998 Annual Report, the U.S. Environmental Protection Agency (Federal
   EPA) issued final rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which the
   generating plants of the Company and its AEP System affiliates are
   located.  The final rules were to be implemented through state
   implementation plans (SIPs).  SIPs are a procedural method used by each
   state to comply with Federal EPA rules.  The NOx SIP Call rule requires
   submission of revised SIPs by September 30, 1999.  A number of utilities,
   including the Company and its AEP System affiliates, filed petitions
   seeking a review of the final rule in the U.S. Court of Appeals for the
   District of Columbia Circuit (Appeals Court).  On May 25, 1999, the
   Appeals Court ordered an indefinite stay of the September 30, 1999
   deadline for submission of SIP revisions pending a further order of the
   court while arguments regarding the SIP Call rule are considered.

       On April 30, 1999, Federal EPA took final action with respect to
   petitions filed by eight northeastern states pursuant to Section 126 of
   the Clean Air Act.  Federal EPA approved portions of the states'
   petitions triggering emission reductions that are substantially the same
   as those that would otherwise have been required by the NOx SIP Call.
   The imposition of these NOx reduction requirements on AEP System
   generating units would be approximately equivalent to the reductions
   contemplated by the stayed SIP Call rule.  On May 28, and June 1, 1999,
   the Utility Air Regulatory Group and the Midwest Ozone Group,
   respectively, each filed a petition in the Appeals Court seeking review
   of Federal EPA's approval of portions of the northeastern states'
   petitions.  In the second quarter of 1999, three additional northeastern
   states filed Section 126 petitions with Federal EPA similar to those
   filed by the eight northeastern states.

       Preliminary estimates indicate that NOx compliance could result in
   required capital expenditures of approximately $130 million for the
   Company.  Compliance costs cannot be estimated with certainty and the
   actual costs incurred to comply could be significantly different from
   this preliminary estimate depending upon the compliance alternatives
   selected to achieve reductions in NOx emissions.  Unless such costs are
   recovered from customers through regulated rates and/or reflected in the
   future market price of electricity if generation is deregulated, they
   will have a material adverse effect on future results of operations, cash
   flows and possibly financial condition.

   Other

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


<PAGE>
   <PAGE>
                          KENTUCKY POWER COMPANY
         MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                SECOND QUARTER 1999 vs. SECOND QUARTER 1998
                                    AND
                  YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998

   Net income increased $0.6 million or 24% for the quarter and $3.8 million
or 51% for the year-to-date period.  The increases in net income were mainly
attributable to increased operating revenues and a decline in maintenance
costs.
   Income statement line items which changed significantly were:
                                      Increase(Decrease)
                               Second Quarter     Year-to-Date
                             (in millions)   %  (in millions)  %

Operating Revenues . . . . . .   $ 2.2       3     $ 5.6       3
Fuel Expense . . . . . . . . .     4.1      23       1.5       4
Purchased Power Expense. . . .    (1.2)     (4)      2.0       4
Other Operation Expense. . . .    (0.2)     (2)      1.1       5
Maintenance Expense. . . . . .    (2.2)    (30)     (6.6)    (40)
Taxes Other Than Federal
  Income Taxes . . . . . . . .     0.4      19       0.5      10
Federal Income Taxes . . . . .     0.4      69       2.6      95

   Operating revenues increased in the second quarter due to increased
wholesale sales primarily to the American Electric Power System Power Pool
(AEP Power Pool) while retail sales declined slightly.  Wholesale sales rose
as a result of increased availability of the Company's generation plant.  In
the second quarter of 1998  one of the two units at the Company's Big Sandy
Plant was on an extended maintenance outage.  The increase in operating
revenues in the year-to-date period was due to increased retail sales
reflecting colder winter weather.
   Fuel expense increased in the second quarter and the year-to-date period
primarily due to increased generation and a rise in the average cost of fuel
consumed.  The increase in generation reflects the absence of an extended
maintenance outage in 1999.  The rise in fuel costs was due to an increase in
the price of coal burned to produce electricity and included in fuel expense
concurrent with recovery through fuel clause revenues.  Changes in the cost
of fuel are deferred until reflected in fuel clause billings to customers.
   The decrease in purchased power expense in the second quarter resulted
from reduced purchases of power from unaffiliated entities and lower average
purchase prices.  The reductions resulted from a decreased need for purchased
energy since the availability of Big Sandy Plant increased and a decline in
demand by unaffiliated wholesale customers mainly due to mild weather.
Purchased power expense increased in the year-to-date period primarily due to
increased capacity charges from the 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.
   Other operation expense increased in the year-to-date period due to
accrual adjustments for employee pensions and benefits recorded in the first
quarter of 1999 and 1998.  The 1999 adjustment was unfavorable while the 1998
adjustment was favorable.
   The decline in maintenance expense is primarily attributable to decreased
overhead distribution line and generating plant maintenance expenditures.  In
the first quarter of 1998 the repair and restoration of customers'
distribution service after winter storm damage and a lengthy scheduled outage
in the second quarter of 1998 for maintenance and repairs of the 260 mw Big
Sandy Plant Unit 1 increased maintenance expense.
   Taxes other than federal income taxes increased in both periods primarily
due to increased state income tax expense reflecting  a rise in taxable
income.
   The increase in federal income tax expense attributable to operations in
both periods was primarily due to an increase in pre-tax operating income.


<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                             Three Months Ended      Six Months Ended
                                                  June 30,                June 30,
                                              1999        1998       1999          1998
                                                           (in thousands)
<S>                                         <C>         <C>       <C>           <C>
OPERATING REVENUES . . . . . . . . . . . .  $498,587    $523,671  $1,016,808    $1,039,343
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . .   169,055     180,947     358,218       374,222
  Purchased Power. . . . . . . . . . . . .    35,699      48,400      56,972        67,990
  Other Operation. . . . . . . . . . . . .    82,829      82,942     167,890       163,843
  Maintenance. . . . . . . . . . . . . . .    28,501      33,158      53,991        63,751
  Depreciation and Amortization. . . . . .    37,397      35,998      74,182        71,861
  Taxes Other Than Federal Income Taxes. .    41,952      41,862      85,805        84,520
  Federal Income Taxes . . . . . . . . . .    29,826      30,499      67,466        64,222
          TOTAL OPERATING EXPENSES . . . .   425,259     453,806     864,524       890,409
OPERATING INCOME . . . . . . . . . . . . .    73,328      69,865     152,284       148,934
NONOPERATING INCOME (LOSS) . . . . . . . .      (492)      3,449       1,508         4,687
INCOME BEFORE INTEREST CHARGES . . . . . .    72,836      73,314     153,792       153,621
INTEREST CHARGES . . . . . . . . . . . . .    20,971      20,255      41,106        40,126
NET INCOME . . . . . . . . . . . . . . . .    51,865      53,059     112,686       113,495
PREFERRED STOCK DIVIDEND REQUIREMENTS. . .       367         368         734           738
EARNINGS APPLICABLE TO COMMON STOCK. . . .  $ 51,498    $ 52,691  $  111,952    $  112,757



               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                             Three Months Ended      Six Months Ended
                                                  June 30,                June 30,
                                              1999        1998       1999          1998
                                                           (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . .  $590,251    $597,442   $587,500     $590,151
NET INCOME . . . . . . . . . . . . . . . .    51,865      53,059    112,686      113,495
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . . .    57,703      52,775    115,406      105,550
    Cumulative Preferred Stock . . . . . .       368         369        735          739

BALANCE AT END OF PERIOD . . . . . . . . .  $584,045    $597,357   $584,045     $597,357

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>
                                                               June 30,      December 31,
                                                                 1999            1998
                                                                    (in thousands)
ASSETS
<S>                                                           <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . . . . .  $2,676,712      $2,646,597
  Transmission . . . . . . . . . . . . . . . . . . . . . . .     851,679         842,318
  Distribution . . . . . . . . . . . . . . . . . . . . . . .     969,875         949,224
  General (including mining assets). . . . . . . . . . . . .     718,745         689,815
  Construction Work in Progress. . . . . . . . . . . . . . .     100,865         129,887
          Total Electric Utility Plant . . . . . . . . . . .   5,317,876       5,257,841
  Accumulated Depreciation and Amortization. . . . . . . . .   2,547,315       2,461,376

          NET ELECTRIC UTILITY PLANT . . . . . . . . . . . .   2,770,561       2,796,465



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . .     246,654         218,311



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . . . . .     101,648          89,652
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . . . . .     288,445         215,665
    Affiliated Companies . . . . . . . . . . . . . . . . . .      82,055          63,922
    Miscellaneous. . . . . . . . . . . . . . . . . . . . . .      22,528          28,139
    Allowance for Uncollectible Accounts . . . . . . . . . .      (2,583)         (1,678)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . .     143,844          94,914
  Materials and Supplies . . . . . . . . . . . . . . . . . .      92,977          86,870
  Accrued Utility Revenues . . . . . . . . . . . . . . . . .      48,911          43,501
  Energy Marketing and Trading Contracts . . . . . . . . . .     175,702          19,790
  Prepayments. . . . . . . . . . . . . . . . . . . . . . . .      41,404          34,523

          TOTAL CURRENT ASSETS . . . . . . . . . . . . . . .     994,931         675,298



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . .     572,025         551,776


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . .      82,570         102,830


            TOTAL. . . . . . . . . . . . . . . . . . . . . .  $4,666,741      $4,344,680


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                                June 30,      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. . . . . . . . . . . . . . . . . . . . . .      462,366         462,335
  Retained Earnings. . . . . . . . . . . . . . . . . . . . .      584,045         587,500
          Total Common Shareholder's Equity. . . . . . . . .    1,367,612       1,371,036
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . . . . .       17,211          17,370
    Subject to Mandatory Redemption. . . . . . . . . . . . .       11,850          11,850
  Long-term Debt . . . . . . . . . . . . . . . . . . . . . .    1,072,702       1,073,456

          TOTAL CAPITALIZATION . . . . . . . . . . . . . . .    2,469,375       2,473,712

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . .      367,663         360,330

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . . . . .       11,283          11,472
  Short-term Debt. . . . . . . . . . . . . . . . . . . . . .      194,090         123,005
  Accounts Payable . . . . . . . . . . . . . . . . . . . . .      261,265         235,787
  Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . .      162,576         161,406
  Interest Accrued . . . . . . . . . . . . . . . . . . . . .       13,367          14,187
  Obligations Under Capital Leases . . . . . . . . . . . . .       29,234          28,310
  Energy Marketing and Trading Contracts . . . . . . . . . .      176,569          22,480
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .       92,750          97,916

          TOTAL CURRENT LIABILITIES. . . . . . . . . . . . .      941,134         694,563

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . .      702,342         711,913

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . .       37,637          39,296

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . . .      148,590          64,866

CONTINGENCIES (Note 7)

            TOTAL. . . . . . . . . . . . . . . . . . . . . .   $4,666,741      $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>

                                                                     Six Months Ended
                                                                         June 30,
                                                                    1999          1998
                                                                      (in thousands)
<S>                                                              <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 112,686     $ 113,495
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . . . .    93,008        87,091
    Deferred Federal Income Taxes. . . . . . . . . . . . . . . .     1,603         2,480
    Deferred Fuel Costs (net). . . . . . . . . . . . . . . . . .   (23,695)      (22,968)
    Amortization of Deferred Property Taxes. . . . . . . . . . .    39,464        38,294
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . . . .   (84,397)     (134,357)
    Fuel, Materials and Supplies . . . . . . . . . . . . . . . .   (55,037)        3,906
    Accrued Utility Revenues . . . . . . . . . . . . . . . . . .    (5,410)       (2,807)
    Prepayments. . . . . . . . . . . . . . . . . . . . . . . . .    (6,881)       (6,055)
    Accounts Payable . . . . . . . . . . . . . . . . . . . . . .    25,478       114,553
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . .     1,170       (19,733)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . . . .    44,808        81,078
        Net Cash Flows From Operating Activities . . . . . . . .   142,797       254,977

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . . . .   (83,279)      (71,323)
  Proceeds from Sale of Property and Other . . . . . . . . . . .       670         3,600
        Net Cash Flows Used For Investing Activities . . . . . .   (82,609)      (67,723)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . . . .   148,215       137,566
  Change in Short-term Debt (net). . . . . . . . . . . . . . . .    71,085        31,400
  Retirement of Cumulative Preferred Stock . . . . . . . . . . .      (128)          (47)
  Retirement of Long-term Debt . . . . . . . . . . . . . . . . .  (151,223)     (185,809)
  Dividends Paid on Common Stock . . . . . . . . . . . . . . . .  (115,406)     (105,550)
  Dividends Paid on Cumulative Preferred Stock . . . . . . . . .      (735)         (739)
        Net Cash Flows Used For Financing Activities . . . . . .   (48,192)     (123,179)

Net Increase in Cash and Cash Equivalents. . . . . . . . . . . .    11,996        64,075
Cash and Cash Equivalents at Beginning of Period . . . . . . . .    89,652        44,203
Cash and Cash Equivalents at End of Period . . . . . . . . . . . $ 101,648     $ 108,278

Supplemental Disclosure:
  Cash paid for interest net  of capitalized amounts was $40,816,000 and $41,125,000 and
  for income taxes  was  $24,645,000  and  $43,019,000 in  1999 and  1998, respectively.
  Noncash acquisitions under capital leases were $11,849,000 and $18,913,000 in 1999 and
  1998, respectively.


See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
               OHIO POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           JUNE 30, 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 ACTIVITY

       In May 1999 the Company issued $50 million of 5.15% Ohio
   Air Quality Series C pollution control revenue bonds due 2026
   and in June 1999 the Company issued $100 million of 6.75%
   senior unsecured notes due 2004.

       During the first six months of 1999, the Company reacquired
   the following first mortgage bonds for $88 million.

                                             Principal
                                               Amount
        % Rate        Due Date               Reacquired
                                           (in thousands)
        6.875         June 1, 2003            $40,000
        6.55          October 1, 2003           7,865
        7.85          June 1, 2023             40,000

       In May 1999 the Company reacquired $50 million of 7.40%
   Ohio Air Quality Series B pollution control revenue bonds due
   2009.

       The short-term debt limitation of the Company was increased
   from $400 million to $450 million with approval of the
   Securities and Exchange Commission.
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. OHIO RESTRUCTURING LEGISLATION

       On July 6, 1999, the Governor of the State of Ohio signed
   The Ohio Electric Restructuring Act of 1999.  The Act provides
   for customer choice of electricity supplier and a residential
   rate reduction of 5% of the unbundled generation rate beginning
   on January 1, 2001.  The Act also provides for a five-year
   transition period to transition from cost based rates to market
   pricing for generation services.  It authorizes the Public
   Utilities Commission of Ohio (PUCO) to address certain major
   transition issues including unbundling of rates and the
   recovery of regulatory assets and other stranded transition
   costs.

       Retail electric services that will be competitive are
   defined in the Act as electric generation service, aggregation
   service, and power marketing and brokering.  The PUCO has been
   granted broad oversight responsibility under the Act.  The Act
   requires the PUCO to promulgate rules for competitive retail
   electric generation service.

       The Act further provides Ohio electric utilities with an
   opportunity to recover PUCO approved allowable transition costs
   through unbundled rates paid by customers who do not switch
   generation suppliers and through a wires charges by customers
   who switch generation suppliers.  Transition costs can include
   regulatory assets, impairments of generating assets and other
   stranded costs, employee severance and retraining costs and
   other costs.  Recovery of transition revenues can under certain
   circumstances extend beyond the five-year transition period but
   cannot continue beyond December 31, 2010.  The Company must
   file a transition plan with the PUCO by January 3, 2000 and the
   PUCO is required to issue a transition order no later than
   October 31, 2000.

       The Act also provides that the property tax assessment
   percentage on electric generation equipment be lowered from
   100% to 25% of value effective January 1, 2001.  Electric
   utilities will also become subject to the Ohio Corporate
   Franchise Tax and municipal income taxes on January 1, 2002.
   The last year for which electric utilities will pay the excise
   tax based on gross receipts is the year ending April 30, 2002.
   As of May 1, 2001 electric distribution companies will be
   subject to an excise tax based on kilowatt-hours sold to Ohio
   customers.  These changes should put the Company's generation
   operations on an equal level with other competitive businesses
   in Ohio regarding state taxation.

       As discussed in Note 2, "Effects of Regulation," of the
   Notes to Consolidated Financial Statements in the 1998 Annual
   Report, the Company defers as regulatory liabilities and assets
   certain revenues and expenses consistent with the regulatory
   process in accordance with Statement of Financial Accounting
   Standards (SFAS) 71, "Accounting for the Effects of Certain
   Types of Regulation."  At June 30, 1999 the amount of
   regulatory assets recorded on the books applicable to the
   generating business is estimated to be $363 million before
   related tax effects.  Whether the Company will have any
   additional stranded transition costs related to an economic
   impairment of its generating assets is dependent on several
   factors including the assumed future market price for
   electricity.  The Company intends to seek recovery in its
   transition filing of all regulatory assets and any other
   stranded transition costs which may be identified. At this time
   management is unable to predict the outcome of the regulatory
   process or its impact on results of operations, cash flows or
   financial condition.  Therefore, the Company will not be
   discontinuing application of SFAS 71 until the regulatory
   process is completed.

       Upon discontinuance of the application of SFAS 71 the
   Company will have to write off its Ohio generation-related
   regulatory assets and record any asset impairments in
   accordance with SFAS 121 "Accounting for the Impairment of
   Long-lived Assets and for Long-lived Assets to Be Disposed Of."
   Absent the determination in the regulatory process of
   transition revenues and other pertinent information, it is not
   possible at this time to determine if any of the Company's
   plants are impaired in accordance with SFAS 121.  Should the
   Company be granted recovery of its regulatory assets and/or any
   economic asset impairments it can record an offsetting
   regulatory asset.  Should the PUCO not approve the Company's
   request for recovery of its generation-related regulatory
   assets and/or other stranded transition costs it would have an
   adverse impact on future results of operations and possibly
   financial condition.  The Company does not expect to be able
   to determine the impact of the legislation on its financial
   statements until the regulatory process is complete.  The PUCO
   is required to complete its regulatory process no later than
   October 31, 2000.

5. WINDSOR MINE CLOSING

       In July 1999 the Company announced that the scheduled
   closing of the affiliated Windsor coal mine was being
   accelerated from December 31, 2000 to April 30, 2000.  The
   liability for closing the mine is estimated to be $48.4 million
   including reclamation costs.  As discussed in Note 3, "Rate
   Matters" of the Notes to Consolidated Financial Statements in
   the 1998 Annual Report, management believes the Ohio
   jurisdictional portion of the cost of the mine shutdown can be
   deferred for future recovery under the terms of the Ohio fuel
   clause predetermined price agreement.  Management intends to
   continue to recover from non-Ohio jurisdictional ratepayers the
   non-Ohio jurisdictional portion of the investment in and the
   liabilities and closing costs of the Windsor mine.  Unless the
   cost of the remaining coal production and mine shutdown are
   recovered, results of operations and cash flows would be
   adversely affected.

<PAGE>
6. RATE MATTERS

       The Federal Energy Regulatory Commission (FERC) issued
   orders 888 and 889 in April 1996 which required each public
   utility that owns or controls interstate transmission
   facilities to file an open access network and point-to-point
   transmission tariff that offers services comparable to the
   utility's own uses of its transmission system.  The orders also
   require utilities to functionally unbundle their services, by
   requiring them to use their own tariffs in making off-system
   and third-party sales.  As part of the orders, the FERC issued
   a pro-forma tariff which reflects the Commission's views on the
   minimum non-price terms and conditions for non-discriminatory
   transmission service.  The orders also allow a utility to seek
   recovery of certain prudently-incurred stranded costs that
   result from unbundled transmission service.

       On July 9, 1996, the AEP System companies filed an Open
   Access Transmission Tariff conforming with the FERC's pro-forma
   transmission tariff, subject to the resolution of certain
   pricing issues.

       On July 29, 1999, the FERC approved a draft order which
   rules on the AEP System's pending Open Access Transmission
   Tariff.  This approved order has certain unfavorable pricing
   issues for which the AEP System has 30 days to seek rehearing.
   If the Commission's order is ultimately upheld the Company as
   a member of the AEP System will have to make refunds including
   interest.  As of June 30, 1999 the Company has not made any
   provisions for its share of a potential refund which is
   preliminarily estimated to be approximately $5 million.

7. 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 June 30,
   1999 would reduce earnings by approximately $117 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 is seeking refunds
   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.

   Air Quality

       As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the U.S.
   Environmental Protection Agency (Federal EPA) issued final
   rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which
   the generating plants of the Company and its AEP System
   affiliates are located.  The final rules were to be implemented
   through state implementation plans (SIPs).  SIPs are a
   procedural method used by each state to comply with Federal EPA
   rules.  The rules require submission of revised SIPs by
   September 30, 1999.  A number of utilities, including the
   Company and its AEP System affiliates, filed petitions seeking
   a review of the final rules in the U.S. Court of Appeals for
   the District of Columbia Circuit (Appeals Court).  On May 25,
   1999, the Appeals Court ordered an indefinite stay of the
   September 30, 1999 deadline for submission of SIP revisions
   pending a further order of the court while arguments regarding
   the SIP call rule are considered.

       On April 30, 1999, Federal EPA took final action with
   respect to petitions filed by eight northeastern states
   pursuant to Section 126 of the Clean Air Act.  Federal EPA
   approved portions of the states' petitions triggering emission
   reductions that are substantially the same as those that would
   otherwise have been required by the NOx SIP call.  On May 28,
   and June 1, 1999, the Utility Air Regulatory Group and the
   Midwest Ozone Group, respectively, each filed a petition in the
   Appeals Court seeking review of Federal EPA's approval of
   portions of the northeastern states' petitions.  In the second
   quarter of 1999, three additional northeastern states filed
   Section 126 petitions with Federal EPA similar to those filed
   by the eight northeastern states.

       Preliminary estimates indicate that NOx compliance could
   result in required capital expenditures of approximately $570
   million for the Company.  Compliance costs cannot be estimated
   with certainty and the actual costs incurred to comply could
   be significantly different from this preliminary estimate
   depending upon the compliance alternatives selected to achieve
   reductions in NOx emissions.  Unless such costs are recovered
   from customers or reflected in the future market price of
   electricity, they will have a material adverse effect on future
   results of operations, cash flows and possibly financial
   condition.

<PAGE>
   Other

       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

           SECOND QUARTER 1999 vs. SECOND QUARTER 1998
                               AND
             YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998

RESULTS OF OPERATIONS
   Net income decreased $1.2 million or 2% in the second quarter
and $0.8 million or 1% in the year-to-date period.  The decline in
both periods is mainly due to a reduction in operating revenues and
nonoperating income.
   Income statement line items which changed significantly were:
                                     Increase (Decrease)
                             Second Quarter       Year-to-Date
                            (in millions)  %   (in millions)   %

Operating Revenues . . . .     $(25.1)    (5)     $(22.5)     (2)
Fuel Expense . . . . . . .      (11.9)    (7)      (16.0)     (4)
Purchased Power Expense. .      (12.7)   (26)      (11.0)    (16)
Maintenance Expense. . . .       (4.7)   (14)       (9.8)    (15)
Nonoperating Income. . . .       (3.9)  (114)       (3.2)    (68)

   Operating revenues decreased for both periods due to a decline
in wholesale energy sales to unaffiliated utilities and the
American Electric Power System Power Pool reflecting the effect of
milder spring weather on demand.
   The decrease in fuel expense in both periods was mainly due to
a decrease in generation resulting from the decreased demand for
energy.
   Purchased power expense decreased in the second quarter
primarily due to the decline in demand for electricity.  In the
year-to-date period a lower average price for purchases from
unaffiliated companies accounted for the decrease in purchased
power expense.  The decrease in the average price reflected the
reduced demand for energy.
   The decline in maintenance expense was primarily due to a
reduction in scheduled generating plant maintenance in 1999.
   Nonoperating income decreased due to the recognition of a
provision for loss related to a Public Utilities Commission of Ohio
(PUCO) order which requires the Company to reprice certain emission
allowance transactions which are included in the electric fuel rate
factor of customers' bills.  The order requires the Company to
adjust the actual amount paid for allowances purchased to the
weighted average cost of allowances surrendered to the United
States Environmental Protection Agency (Federal EPA) as a result of
exceeding sulfur emission limitations in order to make wholesale
sales.
FINANCIAL CONDITION
   Total plant and property additions including capital leases for
the first six months of 1999 were $95 million.
   During the first six months of 1999, the Company retired $138
million principal amount of long-term debt with interest rates
ranging from 6.55% to 7.85%, issued $100 million of senior
unsecured notes at a rate of 6.75% due 2004, issued $50 million of
pollution control revenues bonds at a rate of 5.15% due 2026 and
increased short-term debt by $71 million from year-end balances.
The short-term debt limitation of the Company was increased from
$400 million to $450 million with the approval of the Securities
and Exchange Commission.
OTHER MATTERS
Ohio Restructuring Legislation
   On July 6, 1999, the Governor of the State of Ohio signed The
Ohio Electric Restructuring Act of 1999.  The Act provides for
customer choice of electricity supplier and a residential rate
reduction of 5% of the unbundled generation rate beginning on
January 1, 2001.  The Act also provides for a five-year transition
period to transition from cost based rates to market pricing for
generation services.  It authorizes the PUCO to address certain
major transition issues including unbundling of rates and the
recovery of regulatory assets and other stranded transition costs.
   Retail electric services that will be competitive are defined
in the Act as electric generation service, aggregation service, and
power marketing and brokering.  The PUCO has been granted broad
oversight responsibility under the Act.  The Act requires the PUCO
to promulgate rules for competitive retail electric generation
service.
   The Act further provides Ohio electric utilities with an
opportunity to recover PUCO approved allowable transition costs
through unbundled rates paid by customers who do not switch
generation suppliers and through a wires charges by customers who
switch generation suppliers.  Transition costs can include
regulatory assets, impairments of generating assets and other
stranded costs, employee severance and retraining costs and other
costs.  Recovery of transition revenues can under certain
circumstances extend beyond the five-year transition period but
cannot continue beyond December 31, 2010.  The Company must file a
transition plan with the PUCO by January 3, 2000 and the PUCO is
required to issue a transition order no later than October 31,
2000.
   The Act also provides that the property tax assessment
percentage on electric generation equipment be lowered from 100% to
25% of value effective January 1, 2001.  Electric utilities will
also become subject to the Ohio Corporate Franchise Tax and
municipal income taxes on January 1, 2002.  The last year for which
electric utilities will pay the excise tax based on gross receipts
is the year ending April 30, 2002.  As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on
kilowatt-hours sold to Ohio customers.  These changes should put
the Company's generation operations on an equal level with other
competitive businesses in Ohio regarding state taxation.
   As discussed in Note 2, "Effects of Regulation," of the Notes
to Consolidated Financial Statements in the 1998 Annual Report, the
Company defers as regulatory liabilities and assets certain
revenues and expenses consistent with the regulatory process in
accordance with Statement of Financial Accounting Standards (SFAS)
71, "Accounting for the Effects of Certain Types of Regulation."
At June 30, 1999 the amount of regulatory assets recorded on the
books applicable to the generating business is estimated to be $363
million before related tax effects.  Whether the Company will have
any additional stranded transition costs related to an economic
impairment of its generating assets is dependent on several factors
including the assumed future market price for electricity.  The
Company intends to seek recovery in its transition filing of all
regulatory assets and any other stranded transition costs which may
be identified. At this time management is unable to predict the
outcome of the regulatory process or its impact on results of
operations, cash flows or financial condition.  Therefore, the
Company will not be discontinuing application of SFAS 71 until the
regulatory process is completed.
   Upon discontinuance of the application of SFAS 71 the Company
will have to write off its Ohio generation-related regulatory
assets and record any asset impairments in accordance with SFAS 121
"Accounting for the Impairment of Long-lived Assets and for Long-lived Assets
to Be Disposed Of."  Absent the determination in the
regulatory process of transition revenues and other pertinent
information, it is not possible at this time to determine if any of
the Company's plants are impaired in accordance with SFAS 121.
Should the Company be granted recovery of its generation-related
regulatory assets and/or any economic asset impairments it can
record an offsetting regulatory asset.  Should the PUCO not approve
the Company's request for recovery of its regulatory assets and/or
other stranded transition costs it would have an adverse impact on
future results of operations and possibly financial condition.  The
Company does not expect to be able to determine the impact of the
legislation on its financial statements until the regulatory
process is complete.  The PUCO is required to complete its
regulatory process no later than October 31, 2000.
Windsor Mine Closing
   In July 1999 the Company announced that the scheduled closing
of the affiliated Windsor coal mine was being accelerated from
December 31, 2000 to April 30, 2000.  The liability for closing the
mine is estimated to be $48.4 million including reclamation costs.
As discussed in Note 3, "Rate Matters" of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, management believes
the Ohio jurisdictional portion of the cost of the mine shutdown
can be deferred for future recovery under terms of the Ohio fuel
clause predetermined price agreement.  Management intends to
continue to recover from non-Ohio jurisdictional ratepayers the
non-Ohio jurisdictional portion of the investment in and the
liabilities and closing costs of the Windsor mine.  Unless the cost
of the remaining coal production and mine shutdown are recovered,
results of operations and cash flows would be adversely affected.
Air Quality
   As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, Federal EPA issued final
rules which require reductions in nitrogen oxides (NOx) emissions
in 22 eastern states, including the states in which the generating
plants of the Company and its AEP System affiliates are located.
The final rules were to be implemented through state implementation
plans (SIPs).  SIPs are a procedural method used by each state to
comply with Federal EPA rules.  The rules require submission of
revised SIPs by September 30, 1999.  A number of utilities,
including the Company and its AEP System affiliates, filed
petitions seeking a review of the final rules in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court).  On
May 25, 1999, the Appeals Court ordered an indefinite stay of the
September 30, 1999 deadline for submission of SIP revisions pending
a further order of the court while arguments regarding the SIP call
rule are considered.
   On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act.  Federal EPA approved portions of the
states' petitions triggering emission reductions that are
substantially the same as those that would otherwise have been
required by the NOx SIP call.  On May 28, and June 1, 1999, the
Utility Air Regulatory Group and the Midwest Ozone Group,
respectively, each filed a petition in the Appeals Court seeking
review of Federal EPA's approval of portions of the northeastern
states' petitions.  In the second quarter of 1999, three additional
northeastern states filed Section 126 petitions with Federal EPA
similar to those filed by the eight northeastern states.
   Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $570 million for
the Company.  Compliance costs cannot be estimated with certainty
and the actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions.  Unless such costs are recovered from customers or
reflected in the future market price of electricity, they will have
a material adverse effect on future results of operations, cash
flows and possibly financial condition.

<PAGE>
Market Risks
   The Company has certain market risks inherent in its business
activities 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 June 30, 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.

<PAGE>
   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,
has submitted information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reported summary information to the U.S.
Department of Energy (DOE) regarding the Y2K readiness of electric
utilities.  The fourth and final NERC report, dated August 3, 1999
and entitled: Preparing the Electric Power Systems of North America
for Transition to the Year 2000 - A Status Report and Work Plan,
Second Quarter 1999, states that: "Mission-critical component
testing indicates 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 caused 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.
   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.
   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 the Company's progress toward
becoming ready for the Y2K as of June 30, 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     100%
replacing or retiring                    100%
those mission critical and
high priority digital-based
systems with problems                    Client
processing dates in the                  Server:
Year 2000. Testing these                 100%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.

Costs to Address the Company's Year 2000 Issues - Through June 30,
1999, the Company has spent $11 million on the Y2K project and,
estimates spending an additional $4 million to $6 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 Y2K contingency plan and
submitted it to the East Central Area Reliability Council as part
of NERC's review of regional and individual electric utility
contingency plans in 1999.  In addition, the Company is
establishing 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.
   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, in order to place
   key employees on duty at those locations during the Y2K
   transition.


<PAGE>
<PAGE>
                   PART II.  OTHER INFORMATION

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

American Electric Power Company, Inc. ("AEP")

   The annual meeting of shareholders was held in Charleston, West
Virginia on April 28, 1999.  The holders of shares entitled to vote
at the meeting or their proxies cast votes at the meeting with
respect to the following two matters, as indicated below:

   1.  Election of 10 directors to hold office until the next
       annual meeting and until their successors are duly
       elected.  Each nominee for director received the votes of
       shareholders as follows:

               Number of Shares     Number of
               Nominee              Voted For        Votes With-
held

       John P. DesBarres        152,429,069     1,587,655
       E. Linn Draper, Jr.      152,409,489     1,607,235
       Robert M. Duncan         152,228,331     1,788,393
       Robert W. Fri            152,374,521     1,642,203
       Lester A. Hudson, Jr.    152,399,000     1,617,724
       Leonard J. Kujawa        152,337,815     1,678,909
       Donald G. Smith          152,425,646     1,571,078
       Linda Gillespie Stuntz   152,373,335     1,643,389
       Kathryn D. Sullivan      152,227,130     1,789,594
       Morris Tanenbaum         152,274,788     1,741,936
       Ronald Marsico            55,033

   2.  Approve the appointment by the Board of Directors of
       Deloitte & Touche LLP as independent auditors of AEP for
       the year 1999.  The proposal was approved by a vote of the
       shareholders as follows:

       Votes FOR            152,631,080
       Votes AGAINST            430,714
       Votes ABSTAINED          954,930
       Broker NON-VOTES*              0

<PAGE>
<PAGE>
       *A non-vote occurs when a nominee holding shares for a
       beneficial owner votes on one proposal, but does not vote
       on another proposal because the nominee does not have
       discretionary voting power and has not received
       instructions from the beneficial owner.

Appalachian Power Company ("APCo")

   The annual meeting of stockholders was held on April 27, 1999
at 1 Riverside Plaza, Columbus, Ohio.  At the meeting, 13,499,500
votes were cast FOR each of the following six persons for election
as directors and there were no votes withheld and such persons were
elected directors to hold office for one year or until their
successors are elected and qualify:

       E. Linn Draper, Jr.  James J. Markowsky
       Henry W. Fayne       Armando A. Pena
       William J. Lhota     Joseph H. Vipperman

   No other business was transacted at the meeting.

Indiana Michigan Power Company ("I&M")

   The annual meeting of stockholders was held on April 27, 1999
at 1 Riverside Plaza, Columbus, Ohio.  At the meeting, 1,400,000
votes were cast FOR each of the following thirteen persons for
election as directors and there were no votes withheld and such
persons were elected directors to hold office for one year or until
their successors are elected and qualify:

   Karl G. Boyd        James J. Markowsky       C. R. Boyle, III
   Armando A. Pena     G. A. Clark              David B. Synowiec
   E. Linn Draper, Jr. Joseph H. Vipperman
   Henry W. Fayne      William E. Walters
   James Kobyra        Earl H. Wittkamper
   William J. Lhota

   No other business was transacted at the meeting.

<PAGE>
<PAGE>
Ohio Power Company ("OPCo")

   The annual meeting of shareholders was held on May 4, 1999 at
1 Riverside Plaza, Columbus, Ohio.  At the meeting, 27,952,473
votes were cast FOR each of the following six persons for election
as directors and there were no votes withheld and such persons were
elected directors to hold office for one year or until their
successors are elected and qualify:

       E. Linn Draper, Jr.      James J. Markowsky
       Henry W. Fayne           Armando A. Pena
       William J. Lhota         Joseph H. Vipperman

   No other business was transacted at the meeting.


Item 5.  Other Information.

AEP, AEP Generating Company ("AEGCo"), APCo, Columbus Southern
Power Company ("CSPCo"), I&M, Kentucky Power Company ("KEPCo") and
OPCo

   Reference is made to page 29 of the Annual Report on Form 10-K
for the year ended December 31, 1998 ("1998 10-K") for a discussion
of ambient air quality standards attainment.  On May 14, 1999, the
U.S. Court of Appeals for the District of Columbia Circuit issued
its decision vacating the ambient air quality standard for
particulate matter less than 10 microns in diameter and remanding
the 8-hour air quality standards for ozone and fine particulate
matter (less than 2.5 microns in diameter).  The ruling, in effect,
suspends the ozone and fine particulate matter standards pending
the corrective steps mandated by the court.  The U.S. Environmental
Protection Agency ("Federal EPA") filed a motion for rehearing with
the court on June 28, 1999.

<PAGE>
<PAGE>
   Reference is made to pages 32 and 33 of the 1998 10-K for a
discussion of Federal EPA's proposed regional haze rule.  On July
1, 1999, Federal EPA issued a final rule which requires each state
to develop and implement measures to control emissions from sources
within the state which are reasonably anticipated to contribute to
regional haze within a Class I area (essentially national parks or
wilderness areas).  Deadlines for the states to implement such
measures vary between 2002 and 2008 depending on the particulate
matter attainment status for the areas within each state.  The rule
requires each state to identify sources constructed between 1962
and 1977 which may be eligible for  application of Best Available
Retrofit Technology.  AEP is unable to predict when or to what
extent controls may be required for AEP System generating units to
comply with this rule or the extent of costs which may be incurred.

   Reference is made to page 33 of the 1998 10-K and pages II-1
and II-2 of the Quarterly Report on Form 10-Q for the quarter ended
March 31, 1999, for a discussion of requests issued to AEP under
Section 114 of the Clean Air Act focused on assessing compliance
with the New Source Review and New Source Performance Standard
provisions.  In July 1999, Federal EPA, Region V, issued an
additional request seeking documents and information regarding
capital and maintenance expenditures at Tanners Creek Plant and, in
August 1999, made a site visit to Cardinal Plant.  Federal EPA
staff has advised AEP that it is their preliminary view that there
has been widespread noncompliance at coal fired generating units
within the utility industry (including at several AEP plants) over
the past 20 years with regard to New Source Review requirements.
AEP management does not agree with this view.  An adverse
determination by Federal EPA could result in substantial additional
capital costs and significant penalties for any affected company.
AEP is unable to predict what, if any, further action may be taken
by Federal EPA in respect of this matter or the effect that any
action taken by Federal EPA may have on the financial condition or
the results of operation of AEP.

<PAGE>
<PAGE>
AEP and OPCo

   Reference is made to page 32 of the 1998 10-K for a discussion
of the SO2 limitation applicable to the Kammer Plant.  On July 22,
1999, the West Virginia Division of Environmental Protection,
Office of Air Quality, conducted a public meeting to consider
revised SO2 emission limits for the Kammer Plant and other emission
sources within Marshall County.  The emission limit proposed for
Kammer is 2.7 pounds of SO2 per million Btu.  The limit, if
approved, would conform to the current federally approved emission
limit for Kammer contained in the West Virginia State
Implementation Plan.

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:

         Company
        Reporting    Date of Report     Item Reported

        AEP and I&M  June 24, 1999      Item 5. Other Events

        AEGCo, APCo, CSPCo, KEPCo and OPCo

        No reports on Form 8-K were filed during the quarter ended
        June 30, 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: August 12, 1999