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 SEPTEMBER 30, 1998

           [ ] 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
                1 Riverside Plaza, Columbus, Ohio  43215
                Telephone (614) 223-1000

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 October 31, 1998 was 191,348,743.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
     AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                                FORM 10-Q

                For The Quarter Ended September 30, 1998

                                  INDEX
<CAPTION>
                                                                            Page
Part I.  FINANCIAL INFORMATION
           <S>                                                               <C>        
           American Electric Power Company, Inc. and Subsidiary Companies:
             Consolidated Statements of 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-12
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . .   A-13- A-25

           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-19

           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-8
             Management's Narrative Analysis of Results of Operations . .   D-9 - D-10

           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-23

           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-8
             Management's Narrative Analysis of Results of Operations . .   F-9 - F-10
<PAGE>
                                      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                                         FORM 10-Q

                                      For The Quarter Ended September 30, 1998

                                           INDEX

                                                                            Page

           Ohio Power Company and Subsidiaries:
             Consolidated Statements of Income and
               Consolidated Statements of Retained Earnings . . . . . . .   G-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . .   G-2 - G-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . .   G-4
             Notes to Consolidated Financial Statements . . . . . . . . .   G-5 - G-8
             Management's Discussion and Analysis of Results of 
               Operations and Financial Condition . . . . . . . . . . . .   G-9 - G-18


Part II. OTHER INFORMATION

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

SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   II-4

                                                                                   


     This combined Form 10-Q is separately filed by American Electric Power Company, Inc.,
AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company,
Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company. 
Information contained herein relating to any individual registrant is filed by such
registrant on its own behalf.  Each registrant makes no representation as to information
relating to the other registrants.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
     AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                    CONSOLIDATED STATEMENTS OF INCOME
                (in thousands, except per-share amounts)
                               (UNAUDITED)
<CAPTION>
                                           Three Months Ended       Nine Months Ended
                                              September 30,           September 30,    
                                            1998        1997        1998        1997
<S>                                      <C>         <C>         <C>         <C>
OPERATING REVENUES . . . . . . . . . . . $4,638,133  $1,583,994  $9,546,566  $4,458,221

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    463,012     421,815   1,307,198   1,192,434
  Purchased Power. . . . . . . . . . . .  2,982,625     100,961   5,015,690     156,917
  Other Operation. . . . . . . . . . . .    365,563     302,307     968,011     904,892
  Maintenance. . . . . . . . . . . . . .    130,710     123,781     376,158     347,894
  Depreciation and Amortization. . . . .    145,315     144,342     433,584     447,843
  Taxes Other Than Federal Income Taxes.    124,602     123,943     370,933     372,723
  Federal Income Taxes . . . . . . . . .    114,727      91,755     280,291     267,195

          TOTAL OPERATING EXPENSES . . .  4,326,554   1,308,904   8,751,865   3,689,898

OPERATING INCOME . . . . . . . . . . . .    311,579     275,090     794,701     768,323

NONOPERATING INCOME (LOSS) . . . . . . .     (6,274)     32,835      (5,572)     43,030

INCOME BEFORE INTEREST CHARGES AND
  PREFERRED DIVIDENDS. . . . . . . . . .    305,305     307,925     789,129     811,353

INTEREST CHARGES . . . . . . . . . . . .    107,153     103,378     316,938     300,851

PREFERRED STOCK DIVIDEND REQUIREMENTS
  OF SUBSIDIARIES. . . . . . . . . . . .      2,787       2,801       8,155      15,056

INCOME BEFORE EXTRAORDINARY ITEM . . . .    195,365     201,746     464,036     495,446

EXTRAORDINARY ITEM - U. K. WINDFALL TAX.       -       (110,565)       -       (110,565)

NET INCOME . . . . . . . . . . . . . . . $  195,365  $   91,181  $  464,036  $  384,881

AVERAGE NUMBER OF SHARES OUTSTANDING . .    190,996     189,287     190,538     188,819

EARNINGS PER SHARE:

 Before Extraordinary Item . . . . . . .      $1.02       $1.07       $2.44       $2.62

 Extraordinary Item - U. K. Windfall Tax        -         (0.59)        -         (0.58)

 Net Income. . . . . . . . . . . . . . .      $1.02       $0.48       $2.44       $2.04

CASH DIVIDENDS PAID PER SHARE. . . . . .      $0.60       $0.60       $1.80       $1.80
</TABLE>

See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
     AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                       CONSOLIDATED BALANCE SHEETS
                               (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                               1998           1997    
                                                                 (in thousands)
ASSETS
<S>                                                        <C>            <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $ 9,560,684    $ 9,493,158
  Transmission . . . . . . . . . . . . . . . . . . . .       3,572,360      3,501,580
  Distribution . . . . . . . . . . . . . . . . . . . .       4,749,050      4,654,234
  General (including mining assets and nuclear fuel) .       1,603,876      1,604,671
  Construction Work in Progress. . . . . . . . . . . .         460,591        342,842
          Total Electric Utility Plant . . . . . . . .      19,946,561     19,596,485
  Accumulated Depreciation and Amortization. . . . . .       8,290,285      7,963,636


          NET ELECTRIC UTILITY PLANT . . . . . . . . .      11,656,276     11,632,849




OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .       1,852,341      1,356,504




CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         147,894         91,481
  Accounts Receivable. . . . . . . . . . . . . . . . .         852,460        674,278
  Allowance for Uncollectible Accounts . . . . . . . .         (10,796)        (6,760)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         195,539        224,967
  Materials and Supplies . . . . . . . . . . . . . . .         278,825        263,613
  Accrued Utility Revenues . . . . . . . . . . . . . .         190,425        189,191
  Energy Marketing and Trading Contracts . . . . . . .         185,354          2,306
  Prepayments and Other. . . . . . . . . . . . . . . .          81,259         81,366

          TOTAL CURRENT ASSETS . . . . . . . . . . . .       1,920,960      1,520,442



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .       1,820,407      1,817,540



DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         226,263        288,011


            TOTAL. . . . . . . . . . . . . . . . . . .     $17,476,247    $16,615,346
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
     AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                       CONSOLIDATED BALANCE SHEETS
                               (UNAUDITED)
<CAPTION>
                                                         September 30,    December 31,
                                                              1998            1997    
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                       <C>             <C>
CAPITALIZATION:
  Common Stock-Par Value $6.50:
                                1998          1997
    Shares Authorized . . . .600,000,000   300,000,000
    Shares Issued . . . . . .200,335,149   198,989,981
    (8,999,992 shares were held in treasury) . . . . .    $ 1,302,178     $ 1,293,435
  Paid-in Capital. . . . . . . . . . . . . . . . . . .      1,832,744       1,778,782
  Retained Earnings. . . . . . . . . . . . . . . . . .      1,726,249       1,605,017
          Total Common Shareholders' Equity. . . . . .      4,861,171       4,677,234
  Cumulative Preferred Stocks of Subsidiaries:
    Not Subject to Mandatory Redemption. . . . . . . .         46,257          46,724
    Subject to Mandatory Redemption. . . . . . . . . .        127,605         127,605
  Long-term Debt . . . . . . . . . . . . . . . . . . .      5,408,997       5,129,463

          TOTAL CAPITALIZATION . . . . . . . . . . . .     10,444,030       9,981,026

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .      1,373,685       1,246,537

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .         90,793         294,454
  Short-term Debt. . . . . . . . . . . . . . . . . . .        535,408         555,075
  Accounts Payable . . . . . . . . . . . . . . . . . .        460,917         353,256
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .        299,784         380,771
  Interest Accrued . . . . . . . . . . . . . . . . . .        105,966          76,361
  Obligations Under Capital Leases . . . . . . . . . .        103,984         101,089
  Energy Marketing and Trading Contracts . . . . . . .        180,689           1,983
  Other. . . . . . . . . . . . . . . . . . . . . . . .        503,122         322,687

          TOTAL CURRENT LIABILITIES. . . . . . . . . .      2,280,663       2,085,676

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      2,552,084       2,560,921

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        359,005         376,250

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .        224,362         231,320

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        242,418         133,616

CONTINGENCIES (Note 7)

            TOTAL. . . . . . . . . . . . . . . . . . .    $17,476,247     $16,615,346
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
     AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                  CONSOLIDATED STATEMENTS OF CASH FLOWS
                               (UNAUDITED)
<CAPTION>
                                                                   Nine Months Ended
                                                                     September 30,      
                                                                 1998             1997
                                                                     (in thousands)
<S>                                                          <C>              <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 464,036        $ 384,881
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    462,843          455,494
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     34,486          (35,566)
    Deferred Investment Tax Credits. . . . . . . . . . . . .    (17,245)         (17,510)
    Amortization of Deferred Property Taxes. . . . . . . . .    135,324          132,251
    Amortization of Operating Expenses and
      Carrying Charges (net) . . . . . . . . . . . . . . . .     11,850           24,356
    Extraordinary Loss - U.K. Windfall Tax . . . . . . . . .       -             110,565
    Deferred Costs Under Fuel Clause Mechanisms. . . . . . .    (58,903)         (22,393)
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .   (174,146)         (42,336)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     14,216           10,353
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     (1,234)          25,564
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    107,661            1,442
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (80,987)        (153,434)
    Interest Accrued . . . . . . . . . . . . . . . . . . . .     29,605           36,919
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . .     54,554           (1,933)
    Other Current Assets and Liabilities . . . . . . . . . .    124,541           79,056
  Payment of Disputed Tax and Interest Related to COLI . . .   (302,739)            -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     41,533          (21,714)
        Net Cash Flows From Operating Activities . . . . . .    845,395          965,995

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (557,284)        (496,155)
  Investment in Yorkshire Electricity Group plc. . . . . . .       -            (361,795)
  Other Investments. . . . . . . . . . . . . . . . . . . . .     (9,968)          (7,241)
  Proceeds from Sale of Property . . . . . . . . . . . . . .      8,596            9,733
        Net Cash Flows Used For Investing Activities . . . .   (558,656)        (855,458)

FINANCING ACTIVITIES:
  Issuance of Common Stock . . . . . . . . . . . . . . . . .     62,897           58,045
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    617,656          776,441
  Retirement of Cumulative Preferred Stock . . . . . . . . .       (346)        (433,234)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (548,062)        (325,931)
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (19,667)         188,055
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (342,804)        (339,685)
        Net Cash Flows Used For Financing Activities . . . .   (230,326)         (76,309)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     56,413           34,228 
Cash and Cash Equivalents at Beginning of Period . . . . . .     91,481           57,539
Cash and Cash Equivalents at End of Period . . . . . . . . .  $ 147,894        $  91,767

Supplemental Disclosure:
  Cash paid for interest net of  capitalized amounts  was $278,733,000  and $253,884,000
  and for income taxes was $149,712,000 and $290,682,000 in 1998 and 1997, respectively.
  Noncash  acquisitions  under  capital leases  were $93,823,000  and  $171,947,000  in
  1998 and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
     AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
              CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                               (UNAUDITED)
<CAPTION>
                                           Three Months Ended       Nine Months Ended
                                              September 30,           September 30,    
                                            1998        1997        1998        1997
                                                         (in thousands)
<S>                                      <C>         <C>         <C>         <C>
BALANCE AT BEGINNING OF PERIOD . . . . . $1,645,466  $1,615,039  $1,605,017  $1,547,746

NET INCOME . . . . . . . . . . . . . . .    195,365      91,181     464,036     384,881

DEDUCTIONS:
  Cash Dividends Declared. . . . . . . .    114,583     113,515     342,804     339,685
  Other. . . . . . . . . . . . . . . . .         (1)       -           -            237

BALANCE AT END OF PERIOD . . . . . . . . $1,726,249  $1,592,705  $1,726,249  $1,592,705
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
  AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         SEPTEMBER 30, 1998                     
                           (UNAUDITED)

1.   GENERAL

         The accompanying unaudited consolidated financial state-ments 
     should be read in conjunction with the 1997 Financial
     Statements and Management's Discussion and Analysis of Results
     of Operations and Financial Condition as incorporated in and
     filed with the Form 10-K.  In the opinion of management, the
     financial statements reflect all adjustments (consisting of
     only normal recurring accruals) which are necessary for a fair
     presentation of the results of operations and financial
     condition for interim periods.

2.   FINANCING AND RELATED ACTIVITIES

         During the first nine months of 1998, subsidiaries issued
     $452 million of senior unsecured notes: two series totaling
     $112 million at 6.51% and 6.55% due in 2008 and three series
     totaling $340 million at 7.20%, 7.30% and 7-3/8% due in 2038;
     $125 million of 7.60% junior subordinated deferrable interest
     debentures due in 2038; and increased their outstanding balance
     under a revolving credit agreement by $15 million.

         The proceeds from the above financings were used during
     1998 to retire: $472 million of first mortgage bonds with
     interest rates ranging from 6-3/4% to 9.15% due from 1998 to
     2023; $25 million of variable rate installment purchase
     contracts due in 2025; a $16.7 million term loan with an
     interest rate of 6.85% at maturity; and $10 million of a
     variable rate term loan due in 1999.

         As a result of the redemption of the 6-3/4% series first
     mortgage bonds due in 1998, the restriction on the use of
     retained earnings for the payment of common stock dividends was
     reduced to $6 million.

3.   NEW ACCOUNTING STANDARDS

         Statement of Financial Accounting Standards (SFAS) No. 130
     "Reporting Comprehensive Income" was adopted by the Company in
     the first quarter of 1998.  SFAS No. 130 established the
     standards for reporting and displaying components of
     "comprehensive income," which is the total of net income and
     all transactions not included in net income affecting equity
     except those with shareholders.  For the quarter and year-to-date 
     periods ended September 30, 1998, there were no material
     differences between comprehensive income and net income.
<PAGE>
<PAGE>
         In the first quarter of 1998 the Company adopted the
     American Institute of Certified Public Accountants' Statement
     of Position (SOP) 98-1, "Accounting for the Costs of Computer
     Software Developed or Obtained for Internal Use". The SOP
     requires the capitalization and amortization of certain costs
     of acquiring or developing internal use computer software. 
     Previously the Company expensed all software acquisition and
     development costs.  The SOP must be adopted at the beginning
     of a fiscal year with no restatement or retroactive adjustment
     of prior periods.  The adoption of the SOP effective January
     1, 1998 did not have a material effect on results of
     operations, cash flows or financial condition.

4.   INVESTMENT IN YORKSHIRE

         The Company has a 50% ownership interest in Yorkshire Power
     Group Limited which is accounted for using the equity method. 
     The Company's share of Yorkshire earnings are included in
     nonoperating income.  The following amounts which are not
     included in AEP's consolidated financial statements represent
     summarized consolidated financial information of Yorkshire
     Power Group Limited for the quarter and nine months ended
     September 30, 1998:

                                Quarter          Year-to-Date
                                      (in millions)
     Income Statement Data:
       Operating Revenues        $510.2             $1,677.3
       Operating Income            82.6                264.8
       Net Income                  21.5                 13.6

5.   ENERGY MARKETING AND TRADING

         During 1998, the Company substantially increased the volume
     of its electricity and gas marketing and trading.  The purpose
     of the marketing and trading business is to utilize the
     Company's knowledge of the energy markets in order to improve
     the competitiveness of its generation business and contribute
     to net income, thereby enhancing both customer and shareholder
     value.

         The electricity and gas marketing and trading business
     involves the marketing of energy under physical forward
     contracts at fixed and variable prices and the trading of
     options, futures, swaps and other financial derivative
     contracts at both fixed and variable prices.  Most contracts
     represent physical forward electricity marketing contracts for
     the purchase and sale of electricity in the Company's
     traditional marketing area which are recorded as operating
     revenues and purchased power expense  when the contracts
     settle.  At September 30, 1998, the Company had open marketing
     contracts, not on the balance sheet, in its traditional
     marketing area through the year 2004 to sell electricity with
     a notional value of approximately $1.1 billion and to purchase
     electricity  with  a  notional  value  of approximately $1.1 

<PAGE>
     billion.
         The Company has also purchased and sold electricity and gas
     options, futures and swaps, and entered into forward purchase
     and sale contracts for the future delivery or receipt of
     electricity and gas outside its traditional marketing area. 
     These transactions represent non-regulated trading activities
     that are marked-to-market and recorded in nonoperating income. 
     The unrealized mark-to-market gains and losses from such
     trading activity are reported as assets and liabilities,
     respectively.  At September 30, 1998, the Company has open
     marketing contracts outside its traditional marketing area
     through the year 2008 to sell electricity and gas with a
     notional value of approximately $755 million and to purchase
     electricity and gas with a notional value of approximately $585
     million.

         Dependent on future electricity and gas market conditions
     these activities could produce material income or losses in
     future periods.

6.   PROPOSED MERGER AND ACQUISITION

         As discussed in the Management's Discussion and Analysis
     of Results of Operations and Financial Condition in the 1997
     annual report and the Joint Proxy Statement/Prospectus dated
     April 16, 1998, the Company and Central and South West
     Corporation (CSW) have agreed to merge.  At the May 1998 annual
     meeting, AEP shareholders approved the issuance of AEP common
     shares to effect the merger and approved an increase in the
     authorized shares of AEP Common Stock from 300,000,000 to
     600,000,000.  CSW stockholders approved the merger at their May
     1998 annual meeting.  The companies have filed for necessary
     approvals to merge with the Federal Energy Regulatory
     Commission (FERC), the Securities and Exchange Commission, the
     Nuclear Regulatory Commission (NRC) and all of CSW's state
     regulatory commissions: Arkansas, Louisiana, Oklahoma and
     Texas.  Filings with the Federal Communications Commission and
     the Department of Justice are expected to be made before the
     end of 1998.  The Company's target consummation date for the
     merger is the second quarter of 1999.

         In August 1998 the Arkansas Public Service Commission
     approved the merger, subject to a number of conditions
     including the approval of a regulatory plan for sharing net
     merger savings.  On November 3, 1998 the Company, CSW and CSW's
     Arkansas operating subsidiary, Southwestern Electric Power
     Company, filed a settlement agreement for approval with the
     Arkansas Public Service Commission outlining a regulatory plan,
     agreed to with the Commission staff, which provides for a
     sharing of net merger savings through a reduction of rates for
     Arkansas retail customers.

<PAGE>
<PAGE>
         In October 1998 the Oklahoma Corporation Commission (OCC)
     approved plans by AEP and CSW to submit an amended filing
     seeking approval of the proposed merger.  The amended
     application is being made as a result of an Oklahoma
     administrative law judge's recommendation that the merger
     filing be dismissed without prejudice for lack of information
     regarding the potential impact of the merger on the retail
     electric market in Oklahoma.  Submission of the amended
     application will reset Oklahoma's 90-day statutory time period
     for OCC action on the merger phase of the application.  The
     filing of the amended application should not affect the timing
     of the merger closing.

          In July 1998 the FERC issued an order which confirmed that
     the 250 megawatt firm contract path with the Ameren System is
     available.  The contract path is required for AEP and CSW to
     meet the requirements of the Public Utility Holding Company Act
     of 1935 that the two systems operate on an integrated and
     coordinated basis.  On November 10, 1998, the FERC issued an
     order establishing hearing procedures for the merger.  A
     scheduling conference will be held in November 1998.  The order
     indicated that the review of the proposed merger will address
     the issues of competition, market power and customer protection
     and instructed the companies to refile an updated market power
     study.  The outcome of the FERC scheduling conference could
     extend the targeted completion date of the merger.

         A settlement agreement between AEP, CSW and certain key
     parties to the Texas merger proceeding has been reached.  The
     staff of the Public Utility Commission of Texas was not a
     signatory to the settlement agreement, which resolves all
     issues for the signing parties.  The settlement provides for,
     among other things, the approval of rate reductions to share
     net merger savings and settle existing rate reviews.
     
         The application by CSW's operating subsidiary, Central
     Power and Light Company, to the NRC requesting permission to
     transfer control of the license for the South Texas Project
     nuclear generating station to AEP was approved by the NRC. 

         AEP has a 50% interest in Yorkshire Electricity Group, plc
     and CSW has a 100% interest in Seeboard, plc, two United
     Kingdom (U.K.) regional electricity companies (RECs).  The
     proposed merger of CSW into AEP would result in common
     ownership of these U.K. entities.  As a result, the common
     ownership of two U.K. RECs could be referred by the U.K.
     Secretary of State for Trade and Industry to the U.K. Mergers
     and Monopolies Commission for investigation.

<PAGE>
<PAGE>
         The merger, which is to be accounted for as a pooling of
     interests, is conditioned upon, among other things, the
     approval of the above state and federal regulatory agencies. 
     The transaction must satisfy many conditions, including the
     condition that it must be a pooling, and some of these
     conditions may not be waived by the parties.  The Company is
     unable to predict the outcome or the timing of the required
     regulatory proceedings.

         In September 1998 the Company and Equitable Resources, Inc.
     signed a definitive agreement for the Company to  purchase
     Equitable's natural gas midstream assets and operations for
     approximately $320 million.  The purchase includes an
     intrastate pipeline system, five natural gas processing plants,
     one natural gas storage facility and an energy trading
     business.  The transaction is expected to close in the fourth
     quarter of 1998 and be accounted for as a purchase.

7.   CONTINGENCIES

     Taxes

         As discussed in Note 10, "Federal Income Taxes", of the
     Notes to Consolidated Financial Statements in the 1997
     Financial Statements and Management's Discussion and Analysis
     of Results of Operations and Financial Condition, the Internal
     Revenue Service (IRS) agents auditing the AEP System's
     consolidated federal income tax returns requested a ruling from
     their National Office that certain interest deductions relating
     to corporate owned life insurance (COLI) claimed by the Company
     should not be allowed.  As a result of a suit filed in United
     States District Court (discussed below) this request for ruling
     has been withdrawn.  Adjustments have been or will be proposed
     by the IRS disallowing COLI interest deductions for taxable
     years 1991-96.  A disallowance of the COLI interest deductions
     through September 30, 1998 would reduce earnings by
     approximately $310 million (including interest). The Company
     has made no provision for any possible adverse earnings impact
     from this matter.

         In order to resolve this issue without further delay, on
     March 24, 1998, the Company filed suit against the United
     States in the United States District Court for the Southern
     District of Ohio.  Management believes that it has a
     meritorious position and will vigorously pursue this lawsuit. 
     In July 1998 the Company made a payment of taxes and interest
     attributable to COLI interest deductions for taxable years
     1991-96 to avoid the potential assessment by the IRS of any
     additional above market rate interest on the contested amount. 
     In September 1998 the Company made an additional payment for
     the 1997 tax year.  The payments  were included on the balance
     sheet in other property and investments pending the resolution
     of this matter.  The Company will seek refund, either
     administratively or through litigation, of all amounts paid. 
     In the event the resolution of this matter is unfavorable, it 

<PAGE>
     will have a material adverse impact on results of operations
and cash flows.

     Cook Nuclear Plant Shutdown

         As discussed in Note 4 of the Notes to Consolidated
     Financial Statements in the 1997 Financial Statements and
     Management's Discussion and Analysis of Results of Operations
     and Financial Condition, both units of the Cook Nuclear Plant
     were shut down by Indiana Michigan Power Company (I&M) in
     September 1997 due to questions regarding the operability of
     certain safety systems, which arose during a NRC architect
     engineer design inspection.  The NRC issued a Confirmatory
     Action Letter in September 1997 requiring I&M to address the
     issues identified in the letter.  I&M is working with the NRC
     to resolve the one remaining issue in the letter.

         On April 17, 1998, the NRC notified I&M that it had
     convened a Restart Panel for Cook Plant. On July 30, 1998, I&M
     received a letter from the NRC providing the NRC's list of
     required restart activities. I&M is and will be  meeting with
     the Panel on a regular basis, until the Cook Plant units are
     returned to service, to identify and address the items that
     need to be addressed in order to restart the units. When
     maintenance and other activities required for restart are
     complete, I&M will seek concurrence from the NRC to return the
     Cook Plant to service.  
     
         I&M's current restart schedule indicates Unit 1 is expected
     to return to service by the end of the first quarter of 1999. 
     The restart schedule for Unit 2 has not been completed; 
     however, management anticipates that Unit 2 may return to
     service 90 days after Unit 1.  If the units are not returned
     to service, there could be a material adverse effect on
     financial condition.

         The incremental cost expected to be incurred to restart the
     Cook units is approximately $70 million for 1998, of which $34
     million has been incurred through September 30, 1998.  However,
     approximately $20 million of previously budgeted work for 1998
     at the Cook Plant will not be incurred and will partially
     mitigate the incremental restart costs.  The cost and schedule
     for the outage during 1999 could be significantly impacted if
     additional work is identified beyond the $35 million planned
     for the first quarter.

         On July 24, 1998, I&M received an "adverse trend letter"
     from the NRC indicating that NRC senior managers had determined
     that there had been a slow decline in performance at the Cook
     Plant during the 18 month period preceding the letter.  The
     letter indicated that the NRC will closely monitor efforts to
     address issues at Cook Plant through additional inspection
     activities.

<PAGE>
<PAGE>
         In a letter dated October 13, 1998, the NRC issued to I&M
     a Notice of Violation and a proposed $500,000 civil penalty for
     alleged violations at the Cook Plant discovered during five
     inspections conducted between August 4, 1997 and April 15,
     1998. I&M paid the penalty.

         The cost of electricity supplied to I&M's retail customers
     rose due to the outage of the two units since higher cost coal-fired 
     generation and purchased power were substituted for low
     cost nuclear generation.  In the Indiana and Michigan retail
     jurisdictions fuel cost recovery mechanisms permit the
     recovery, subject to regulatory commission review and approval,
     of changes in fuel costs including the fuel component of
     purchased power in the Indiana jurisdiction and changes in
     replacement power in the Michigan jurisdiction.  Under the fuel
     cost recovery mechanisms, retail rates contain a fuel cost
     adjustment factor that reflects estimated fuel costs for the
     period during which the factor will be in effect subject to
     reconciliation to actual fuel costs in a future proceeding. 
     When actual fuel costs exceed the estimated costs reflected in
     the billing factor as was the case with regard to the Cook
     outage, a regulatory asset is recorded and revenues are
     accrued.

         Due to the unscheduled Cook Plant outage, I&M's actual fuel
     costs significantly exceeded the estimated fuel costs reflected
     in its fuel cost adjustment factors.  A regulatory asset has
     been recorded for revenues accrued in anticipation of future
     reconciliation and billing of the higher fuel costs to
     customers.  At September 30, 1998, the regulatory asset was $61
     million.

         The Indiana Utility Regulatory Commission approved two
     agreements authorizing I&M during the billing months of July
     through December 1998 to apply a fuel cost adjustment factor
     less than that requested by I&M, subject to future
     reconciliation or refund.  The agreements provide the parties
     to the proceedings with the opportunity to conduct discovery
     regarding certain issues that were raised in the proceedings,
     including the appropriateness of recovery of replacement energy
     cost due to the extended Cook Plant outage, in anticipation of
     resolving the issues in a future fuel cost adjustment
     proceeding.  Management believes that it should be able to
     recover the Cook replacement energy costs; however, if recovery
     of the replacement costs is denied, results of operations and
     cash flows would be adversely affected.

     Revised Air Quality Standards

         The United States Environmental Protection Agency (Federal
     EPA) published in October 1997 a proposed nitrogen oxides (NOx)
     emissions reduction rule which called for new state
     implementation plans (SIPs).  SIPs are a procedural method used
     by each state to comply with Federal EPA rules.  Eight
     northeastern states also filed petitions in 1997 with Federal 

<PAGE>
     EPA claiming NOx emissions from plants in midwestern states   prevent 
     them from complying with air quality standards.

         On September 24, 1998, Federal EPA issued final rules which
     require reductions in NOx emissions in 22 eastern states,
     including the states in which the Company's generating plants
     are located.  The implementation of the final rules would be
     achieved through the revision of SIPs by September 1999 that,
     by the year 2003, anticipate the imposition of a NOx reduction
     on utility sources of approximately 85% below 1990 emission
     levels.  On October 30, 1998, a number of utilities, including
     the operating companies of the AEP System, filed a petition in
     the U.S. Court of Appeals for the District of Columbia Circuit
     seeking a review of the final rules.

         Should the states fail to adopt the required revisions to
     their SIPs within one year of the date of the final rules
     (September 24, 1999), Federal EPA has proposed to implement a
     federal plan to accomplish the NOx reductions.  Federal EPA
     also proposed the approval of portions of the petitions filed
     by the eight northeastern states that would result in
     imposition of NOx emission reductions on utility and industrial
     sources.  These reductions are substantially the same as those
     required by the final rules and could be adopted by Federal EPA
     in the event the states fail to implement SIPs in accordance
     with the final rules.

         Based on initial studies, preliminary estimates indicate
     that compliance costs could result in required capital
     expenditures by the Company of approximately $1.2 billion. 
     Compliance costs can not be estimated with certainty and the
     actual costs incurred to comply could be significantly
     different from the preliminary estimate depending upon the
     compliance alternatives selected to achieve reductions in NOx
     emissions.  Unless such costs are recovered from customers,
     they would have a material adverse effect on results of
     operations, cash flows and possibly financial condition.
     
     Other

         The Company continues to be involved in certain other
     matters discussed in the 1997 Financial Statements and
     Management's Discussion and Analysis of Results of Operations
     and Financial Condition.
<PAGE>
<PAGE>
  AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                      AND FINANCIAL CONDITION                   

            THIRD QUARTER 1998 vs. THIRD QUARTER 1997
                               AND
             YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
RESULTS OF OPERATIONS
     Net income increased by $104.2 million or 114% for the quarter
and $79.2 million or 21% for the year-to-date period due
predominantly to the effect of an extraordinary loss from a United
Kingdom (U.K.) one-time windfall tax enacted during the third
quarter of 1997 and a significant increase in net revenues from
energy sales due to favorable weather and energy marketing and
trading activities within AEP's traditional marketing area.  The
windfall tax was based on a revision or recomputation of the
original 1990 privatization value of certain privatized regional
electric companies in the U.K. including Yorkshire Electricity
Group.  Income before extraordinary item decreased $6.4 million for
the third quarter and $31.4 million for the year-to-date period as
a result of a write-down of Yorkshire Electricity Group's
investment in Ionica, a U.K. telecommunications company,
expenditures to prepare the Cook Plant for restart following an
extended outage and certain losses on energy trades outside of
AEP's traditional marketing area.
     The significant changes in income statement line items and net
revenues were:
                                    Increase (Decrease)         
                             Third Quarter       Year-to-Date   
                          (in millions)   %   (in millions)   % 

Operating Revenues . . . .   $3,054.1    193     $5,088.3    114
Fuel Expense . . . . . . .       41.2     10        114.8     10
Purchased Power Expense. .    2,881.7    N.M.     4,858.8    N.M.
  Net Revenues . . . . . .      131.2               114.7
Other Operation Expense. .       63.3     21         63.1      7
Maintenance Expense. . . .        6.9      6         28.3      8
Federal Income Taxes . . .       23.0     25         13.1      5
Nonoperating Income. . . .      (39.1)  (119)       (48.6)  (113)

N.M. = Not Meaningful

<PAGE>
<PAGE>
     Operating revenues increased significantly in both the third
quarter and the year-to-date periods due predominantly to increased
sales to retail and wholesale customers.  Energy sales to retail
customers rose 6% in the quarter and 4% in the year-to-date period
primarily due to warmer summer weather in 1998 and increased
industrial customer usage.  The significant increases in wholesale
sales and wholesale revenues are attributable to growth in the
power marketing and trading business in AEP's marketing area.
     The increases in fuel expense were primarily attributable to
an increase in coal-fired generation to meet the increased demand
for electricity and an increase in the average cost of fuel
consumed reflecting the unavailability of lower cost nuclear
generation due to the unplanned outage of both Cook Plant nuclear
units in 1998.
     Purchases of electricity by the wholesale power marketing and
trading business accounted for the significant increase in
purchased power expense.
     The increase in net revenues of $131 million for the quarter
and $115 million for the year-to-date period is due to the impact
of warmer summer weather and increased industrial usage on retail
sales and the successful trading of wholesale energy in a volatile
market.
     The increases in other operation expenses are related to the
increases in energy sales and the extended Cook Plant outage and in
the third quarter increased incentive pay accruals.
     Maintenance expense increased for the year-to-date period
largely as a result of expenditures to prepare the Cook Plant units
for restart and to repair and restore service interruptions caused
by two severe snowstorms.
     Federal income tax expense attributable to operations increased
due to an increase in pre-tax operating income. 
     The decreases in nonoperating income for both periods reflect
the effect of the Company's equity share of Yorkshire's loss on its
investment in Ionica, losses on certain energy trades and in the
third quarter the effect of $26 million of tax benefits recognized
in 1997 related to a reduction of the corporate income tax rate in
the U.K. by Yorkshire and the utilization of certain foreign tax 

<PAGE>
credits.  The energy trades which produced the losses are marked-to-market 
and represent non-regulated trading activities outside
the Company's traditional marketing area (see footnote 5). 
Although losses were incurred on these non-regulated energy trades,
net revenues from power marketing and trading operations within the
Company's traditional marketing area were significantly larger.
FINANCIAL CONDITION
     Total plant and property additions including capital leases for
the first nine months of 1998 were $652 million.
     During the first nine months of 1998, subsidiaries issued $608
million principal amount of long-term obligations at interest rates
ranging from 5.87% to 10.53%; retired $524 million principal amount
of long-term debt with interest rates ranging from 2.85% to 9.15%;
and decreased short-term debt by $20 million.
COOK NUCLEAR PLANT SHUTDOWN
     As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1997 Financial Statements and Management's
Discussion and Analysis of Results of Operations and Financial
Condition, both units of the Cook Nuclear Plant were shut down by
Indiana Michigan Power Company (I&M) in September 1997 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 I&M to address the issues
identified in the letter.  I&M is working with the NRC to resolve
the one remaining issue in the letter.
     On April 17, 1998, the NRC notified I&M that it had convened
a Restart Panel for Cook Plant. On July 30, 1998, I&M received a
letter from the NRC providing the NRC's list of required restart
activities. I&M is and will be  meeting with the Panel on a regular
basis, until the Cook Plant units are returned to service, to
identify and address the items that need to be addressed in order
to restart the units.  When maintenance and other activities
required for restart are complete, I&M will seek concurrence from
the NRC to return the Cook Plant to service.  
<PAGE>
<PAGE>
     I&M's current restart schedule indicates Unit 1 is expected to
return to service by the end of the first quarter of 1999.  The
restart schedule for Unit 2 has not been completed;  however,
management anticipates that Unit 2 may return to service 90 days
after Unit 1.  If the units are not returned to service, there
could be a material adverse effect on financial condition.
     The incremental cost expected to be incurred to restart the
Cook units is approximately $70 million for 1998, of which $34
million has been incurred through September 30, 1998.  However,
approximately $20 million of previously budgeted work for 1998 at
the Cook Plant will not be incurred and will partially mitigate the
incremental restart costs.  The cost and schedule for the outage
during 1999 could be significantly impacted if additional work is
identified beyond the $35 million planned for the first quarter.
     On July 24, 1998, I&M received an "adverse trend letter" from
the NRC indicating that NRC senior managers had determined that
there had been a slow decline in performance at the Cook Plant
during the 18 month period preceding the letter.  The letter
indicated that the NRC will closely monitor efforts to address
issues at Cook Plant through additional inspection activities.
     In a letter dated October 13, 1998, the NRC issued to I&M a
Notice of Violation and proposed a $500,000 civil penalty for
alleged violations at the Cook Plant discovered during five
inspections conducted between August 4, 1997 and April 15, 1998.
I&M paid the penalty.
     The cost of electricity supplied to I&M's retail customers rose
due to the outage of the two units since higher cost coal-fired
generation and purchased power were substituted for low cost
nuclear generation.  In the Indiana and Michigan retail
jurisdictions fuel cost recovery mechanisms permit the recovery,
subject to regulatory commission review and approval, of changes in
fuel costs including the fuel component of purchased power in the
Indiana jurisdiction and changes in replacement power in the
Michigan jurisdiction.  Under the fuel cost recovery mechanisms,
retail rates contain a fuel cost adjustment factor that reflects
estimated fuel costs for the period during which the factor will be
in effect subject to reconciliation to actual fuel costs in a 

<PAGE>
future proceeding.  When actual fuel costs exceed the estimated
costs reflected in the billing factor as was the case with regard
to the Cook outage, a regulatory asset is recorded and revenues are
accrued.
     Due to the unscheduled Cook Plant outage, I&M's actual fuel
costs significantly exceeded the estimated fuel costs reflected in
its fuel cost adjustment factors.  A regulatory asset has been
recorded for revenues accrued in anticipation of future
reconciliation and billing of the higher fuel costs to customers. 
At September 30, 1998, the regulatory asset was $61 million.
     The Indiana Utility Regulatory Commission approved two
agreements authorizing I&M during the billing months of July
through December 1998 to apply a fuel cost adjustment factor less
than that requested by I&M, subject to future reconciliation or
refund.  The agreements provide the parties to the proceedings with
the opportunity to conduct discovery regarding certain issues that
were raised in the proceedings, including the appropriateness of
the recovery of replacement energy cost due to the extended Cook
Plant outage, in anticipation of resolving the issues in a future
fuel cost adjustment proceeding.  Management believes that it
should be able to recover the Cook replacement energy costs;
however, if recovery of the replacement costs is denied, results of
operations and cash flows would be adversely affected.
     The above timetable for the return to service of the Cook Plant
constitute "forward looking statements" as defined in the Private
Securities Litigation Reform Act of 1995.  Such statements and
estimates could differ materially from actual results because of
factors referred to specifically in connection with such forward-looking
statements and, in addition, other unforeseen issues
encountered in preparing the Cook Plant for restart and the
unpredictability of the NRC regulatory process.
REVISED AIR QUALITY STANDARDS
     The United States Environmental Protection Agency (Federal EPA)
published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state implementation
plans (SIPs).  SIPs are a procedural method used by each state to
comply with Federal EPA rules.  Eight northeastern states also 

<PAGE>
filed petitions in 1997 with Federal EPA claiming NOx emissions
from plants in midwestern states prevent them from complying with
air quality standards.
     On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states, including
the states in which the Company's generating plants are located. 
The implementation of the final rules would be achieved through the
revision of SIPs by September 1999 that, by the year 2003,
anticipate the imposition of a NOx reduction on utility sources of
approximately 85% below 1990 emission levels.  On October 30, 1998,
a number of utilities, including the operating companies of the AEP
System, filed a petition in the U.S. Court of Appeals for the
District of Columbia Circuit seeking a review of the final rules.
     Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions.  Federal EPA also proposed the
approval of portions of the petitions filed by the eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources.  These reductions are
substantially the same as those required by the final rules and
could be adopted by Federal EPA in the event the states fail to
implement SIPs in accordance with the final rules.
     Based on initial studies, preliminary estimates indicate that
compliance costs could result in required capital expenditures by
AEP of approximately $1.2 billion.  Compliance costs can not 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, they would have a material adverse effect on results of
operations, cash flows and possibly financial condition.
ENERGY MARKETING AND TRADING
     During 1998, the Company substantially increased the volume of
its electricity and gas marketing and trading.  The purpose of the
marketing and trading business is to utilize the Company's
knowledge of the energy markets in order to improve the 

<PAGE>
competitiveness of its generation business and contribute to net
income, thereby enhancing both customer and shareholder value.
     The electricity and gas marketing and trading business involves
the marketing of energy under physical forward contracts at fixed
and variable prices and the trading of options, futures, swaps and
other financial derivative contracts at both fixed and variable
prices.  Most contracts represent physical forward electricity
marketing contracts for the purchase and sale of electricity in the
Company's traditional marketing area which are recorded as
operating revenues and purchased power expense  when the contracts
settle.  At September 30, 1998, the Company had open marketing
contracts, not marked-to-market on its balance sheet, in its
traditional marketing area through the year 2004 to sell
electricity with a notional value of approximately $1.1 billion and
to purchase electricity with a notional value of approximately $1.1
billion.
     The Company has also purchased and sold electricity and gas
options, futures and swaps, and entered into forward purchase and
sale contracts for the future delivery or receipt of electricity
and gas outside its traditional marketing area.  These transactions
represent non-regulated trading activities that are
marked-to-market and recorded in nonoperating income.  The
unrealized mark-to-market gains and losses from such trading
activity are reported as assets and liabilities, respectively.  At
September 30, 1998, the Company has open marketing contracts
outside its traditional marketing area through the year 2008 to
sell electricity and gas with a notional value of approximately
$755 million and to purchase electricity and gas with a notional
value of approximately $585 million.
     Dependent on future electricity and gas market conditions these
activities could produce material income or losses in future
periods.
TAXES
     As discussed in Note 10, "Federal Income Taxes", of the Notes
to Consolidated Financial Statements in the 1997 Financial
Statements and Management's Discussion and Analysis of Results of
Operations and Financial Condition, the Internal Revenue Service 

<PAGE>
(IRS) agents auditing the AEP System's consolidated federal income
tax returns requested a ruling from their National Office that
certain interest deductions relating to corporate owned life
insurance (COLI) claimed by the Company should not be allowed.  As
a result of a suit filed in United States District Court (discussed
below) this request for ruling has been withdrawn.  Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96.  A disallowance of the COLI
interest deductions through September 30, 1998 would reduce
earnings by approximately $310 million (including interest). The
Company has made no provision for any possible adverse earnings
impact from this matter.
     In order to resolve this issue without further delay, on March
24, 1998, the Company filed suit against the United States in the
United States District Court for the Southern District of Ohio. 
Management believes that it has a meritorious position and will
vigorously pursue this lawsuit.  In July 1998 the Company made a
payment of taxes and interest attributable to COLI interest
deductions for taxable years 1991-96 to avoid the potential
assessment by the IRS of any additional above market rate interest
on the contested amount.  In September 1998 the Company made an
additional payment for the 1997 tax year.  The payments  were
included on the balance sheet in other property and investments
pending the resolution of this matter.  The Company will seek
refund, either administratively or through litigation, of all
amounts paid.  In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations and cash flows.
COMPUTER ISSUE - YEAR 2000
     On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems were 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-Year 

<PAGE>
2000 ready programs.
     Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Year 2000-related failures and repair such failures if they occur. 
This includes both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), 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 Year 2000 readiness.
     Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system. 
AEP, along with other electric utilities in North America,
regularly submits information to the North American Electric
Reliability Council (NERC) as part of NERC's Year 2000 readiness
program.  NERC then publicly reports summary information to the
U.S. Department of Energy regarding the Year 2000 readiness of
electric utilities.  In 1999 AEP plans to participate in two
NERC-sponsored coordinated electric industry Year 2000 readiness
drills.  The first NERC report, dated September 17, 1998 and titled
Preparing the Electric Power Systems of North America for
Transition to the Year 2000-A Status Report and Work Plan, states
that: "Mission critical systems and components are to be made Y2K
Ready by June 30, 1999."  In addition, the report indicates that:
"While many organizations are on track to meet these targets, many
others need to accelerate project plans and resources."  In
response to the report, the Company has accelerated its Year 2000
readiness date for mission critical and high priority systems and
components from September 30, 1999 to June 30, 1999.
     Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems.  Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.<PAGE>
<PAGE>
     Various state regulatory commissions are also reviewing the
Year 2000 readiness of electric utilities subject to their
jurisdiction.

     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,
communications, and the physical generation and delivery of energy;
followed by back office activities such as customer
service/billing, regulatory reporting, internal reporting and
administrative activities (e.g. payroll, procurement, accounts
payable); and finally, those activities that would cause
inconvenience or productivity loss in normal business operations.
     The following chart shows our progress toward becoming ready
for the Year 2000 as of September 30, 1998:
                             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%         11/30/1998    86%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
<PAGE>
<PAGE>
Remediation/Testing: The
process of modifying,       6/30/1999     Mainframe     6/30/1999     2%
replacing or retiring                     60%
those mission critical and                        
high priority digital-based
systems with problems                     Client
processing dates past the                 Server:
Year 2000. Testing these                  1%
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
September 30, 1998, the Company has spent $15 million on the Year
2000 project and, estimates spending an additional $41 million to
$53 million to achieve Year 2000 readiness.  Most Year 2000 costs
are software, IT consultant and salary-related 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 Year 2000 ready 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 Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Year 2000 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.

<PAGE>
<PAGE>
     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.

     In addition, although as discussed 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, Year 2000-related issues may materially adversely
affect AEP.

     Company's Contingency Plans - The Company intends to establish
contingency plans on a case-by-case basis to address alternatives
if Year 2000 failures of automatic systems and equipment occur as
part of its Year 2000 readiness program.  The contingency plans
will be based upon a risk analysis process and will be developed by
the fourth quarter of 1999.  These plans will build upon disaster
recovery, system restoration, and contingency planning that we now
have in place.  We have begun the contingency planning process,
including the review of NERC's Contingency Planning Guide.  The
Company plans to submit a draft of its contingency plans to NERC as
part of NERC's review of drafts of regional and individual electric
utility contingency plans in 1999.

     Forward-Looking Statements - This description of Year 2000
problems, the consequences of Year 2000 failures and the estimated
costs of, and timetable for, becoming Year 2000 ready constitute
"forward looking statements" as defined in the Private Securities
Litigation Reform Act of 1995.  Such statements are based on 

<PAGE>
management's beliefs as well as assumptions made by, and
information currently available to, management.  Investors are
cautioned that such statements and estimates could differ
materially from actual results because of factors referred to
specifically in connection with such forward-looking statements
and, in addition, the following other factors, among others:
     *   Continuing availability of experienced consultants and IT
         personnel and related resources
     *   Ability of third parties to complete their Year 2000
         remediations on a timely basis and accuracy of
         representations made by such third parties concerning
         their Year 2000 readiness
     *   Ability of the Company to identify and implement
         contingency plans.

PROPOSED MERGER AND ACQUISITION
     As discussed in the Management's Discussion and Analysis of
Results of Operations and Financial Condition in the 1997 annual
report and the Joint Proxy Statement/Prospectus dated April 16,
1998, the Company and Central and South West Corporation (CSW) have
agreed to merge.  At the May 1998 annual meeting, AEP shareholders
approved the issuance of AEP common shares to effect the merger and
approved an increase in the authorized shares of AEP Common Stock
from 300,000,000 to 600,000,000.  CSW stockholders approved the
merger at their May 1998 annual meeting.  The companies have filed
for necessary approvals to merge with the Federal Energy Regulatory
Commission (FERC), the Securities and Exchange Commission, the NRC
and all of CSW's state regulatory commissions: Arkansas, Louisiana,
Oklahoma and Texas.  Filings with the Federal Communications
Commission and the Department of Justice are expected to be made
before the end of 1998.  The Company's target consummation date for
the merger is the second quarter of 1999.
     In August 1998 the Arkansas Public Service Commission approved
the merger, subject to a number of conditions including the
approval of a regulatory plan for sharing net merger savings.  On
November 3, 1998 the Company, CSW and CSW's Arkansas operating
subsidiary, Southwestern Electric Power Company, filed a settlement 

<PAGE>
agreement for approval with the Arkansas Public Service Commission
outlining a regulatory plan, agreed to with the Commission staff,
which provides for a sharing of net merger savings through a
reduction of rates for Arkansas retail customers.
     In October 1998 the Oklahoma Corporation Commission (OCC)
approved plans by AEP and CSW to submit an amended filing seeking
approval of the proposed merger.  The amended application is being
made as a result of an Oklahoma administrative law judge's
recommendation that the merger filing be dismissed without
prejudice for lack of information regarding the potential impact of
the merger on the retail electric market in Oklahoma.  Submission
of the amended application will reset Oklahoma's 90-day statutory
time period for OCC action on the merger phase of the application. 
The filing of the amended application should not affect the timing
of the merger closing.
      In July 1998 the FERC issued an order which confirmed that the
250 megawatt firm contract path with the Ameren System is
available.  The contract path is required for AEP and CSW to meet
the requirements of the Public Utility Holding Company Act of 1935
that the two systems operate on an integrated and coordinated
basis.  On November 10, 1998, the FERC issued an order establishing
hearing procedures for the merger.  A scheduling conference will be
held in November 1998.  The order indicated that the review of the
proposed merger will address the issues of competition, market
power and customer protection and instructed the companies to
refile an updated market power study.  The outcome of the FERC
scheduling conference could extend the targeted completion date of
the merger.
     A settlement agreement between AEP, CSW and certain key parties
to the Texas merger proceeding has been reached.  The staff of the
Public Utility Commission of Texas was not a signatory to the
settlement agreement, which resolves all issues for the signing
parties.  The settlement provides for, among other things, the
approval of rate reductions to share net merger savings and settle
existing rate reviews.
<PAGE>
<PAGE>
     The application by CSW's operating subsidiary, Central Power
and Light Company, to the NRC requesting permission to transfer
control of the license for the South Texas Project nuclear
generating station to AEP was approved by the NRC. 
     AEP has a 50% interest in Yorkshire Electricity Group, plc and
CSW has a 100% interest in Seeboard, plc, two U.K. regional
electricity companies (RECs).  The proposed merger of CSW into AEP
would result in common ownership of these U.K. entities.  As a
result, the common ownership of two U.K. RECs could be referred by
the U.K. Secretary of State for Trade and Industry to the U.K.
Mergers and Monopolies Commission for investigation.
     The merger, which is to be accounted for as a pooling of
interests, is conditioned upon, among other things, the approval of
the above state and federal regulatory agencies.  The transaction
must satisfy many conditions, including the condition that it must
be a pooling, and some of these conditions may not be waived by the
parties.  The Company is unable to predict the outcome or the
timing of the required regulatory proceedings.
     In September 1998 the Company and Equitable Resources, Inc.
signed a definitive agreement for the Company to  purchase
Equitable's natural gas midstream assets and operations for
approximately $320 million.  The purchase includes an intrastate
pipeline system, five natural gas processing plants, one natural
gas storage facility and an energy trading business.  The
transaction is expected to close in the fourth quarter of 1998 and
be accounted for as a purchase.
<PAGE>
<PAGE>
<TABLE>
                        AEP GENERATING COMPANY
                         STATEMENTS OF INCOME
                              (UNAUDITED)
<CAPTION>
                                           Three Months Ended      Nine Months Ended
                                              September 30,          September 30,    
                                             1998      1997         1998        1997
                                                         (in thousands)
<S>                                        <C>       <C>         <C>         <C>
OPERATING REVENUES . . . . . . . . . . .   $59,262    $58,136     $167,596    $170,665

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    27,953     26,354       71,718      72,443
  Rent - Rockport Plant Unit 2 . . . . .    17,071     17,071       51,212      51,212
  Other Operation. . . . . . . . . . . .     2,174      2,518        7,547       8,362
  Maintenance. . . . . . . . . . . . . .     2,703      2,372        9,110      10,115
  Depreciation . . . . . . . . . . . . .     5,405      5,402       16,229      16,209
  Taxes Other Than Federal Income Taxes.       882      1,015        2,759       2,744
  Federal Income Taxes . . . . . . . . .       845        922        2,562       2,529

          TOTAL OPERATING EXPENSES . . .    57,033     55,654      161,137     163,614

OPERATING INCOME . . . . . . . . . . . .     2,229      2,482        6,459       7,051

NONOPERATING INCOME. . . . . . . . . . .       837        831        2,457       2,631

INCOME BEFORE INTEREST CHARGES . . . . .     3,066      3,313        8,916       9,682

INTEREST CHARGES . . . . . . . . . . . .       903        986        2,494       2,997

NET INCOME . . . . . . . . . . . . . . .   $ 2,163    $ 2,327     $  6,422    $  6,685

                                                     

                    STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)

                                           Three Months Ended      Nine Months Ended
                                              September 30,          September 30,    
                                             1998      1997         1998        1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . .    $2,435    $3,672       $2,528      $1,886

NET INCOME . . . . . . . . . . . . . . .     2,163     2,327        6,422       6,685

CASH DIVIDENDS DECLARED. . . . . . . . .     2,176     3,286        6,528       5,858

BALANCE AT END OF PERIOD . . . . . . . .    $2,422    $2,713       $2,422      $2,713

                    

The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
</TABLE>
See Notes to Financial Statements.<PAGE>
<PAGE>
<TABLE>
                        AEP GENERATING COMPANY
                            BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>

                                                            September 30,  December 31,
                                                                 1998          1997   

                                                                   (in thousands)

ASSETS
<S>                                                           <C>            <C>
ELECTRIC UTILITY PLANT:
  Production. . . . . . . . . . . . . . . . . . . . . . . .   $629,055       $627,803
  General . . . . . . . . . . . . . . . . . . . . . . . . .      3,151          3,137
  Construction Work in Progress . . . . . . . . . . . . . .      2,510          2,510
          Total Electric Utility Plant. . . . . . . . . . .    634,716        633,450
  Accumulated Depreciation. . . . . . . . . . . . . . . . .    272,198        257,191


          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .    362,518        376,259




CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .        142            237
  Accounts Receivable . . . . . . . . . . . . . . . . . . .     22,674         20,710
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .     12,097         10,107
  Materials and Supplies. . . . . . . . . . . . . . . . . .      4,126          4,246
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .        152            368


          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     39,191         35,668



REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      6,044          5,639



DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      1,570          1,492



            TOTAL . . . . . . . . . . . . . . . . . . . . .   $409,323       $419,058
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
<TABLE>
                        AEP GENERATING COMPANY
                            BALANCE SHEETS
                              (UNAUDITED)
<CAPTION>
                                                           September 30,   December 31,
                                                                1998           1997   

                                                                  (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                           <C>            <C>
CAPITALIZATION:
  Common Stock - Par Value $1,000:
    Authorized and Outstanding - 1,000 Shares . . . . . . .   $  1,000       $  1,000
  Paid-in Capital . . . . . . . . . . . . . . . . . . . . .     36,235         39,235
  Retained Earnings . . . . . . . . . . . . . . . . . . . .      2,422          2,528
          Total Common Shareholder's Equity . . . . . . . .     39,657         42,763
  Long-term Debt. . . . . . . . . . . . . . . . . . . . . .     44,790         69,570

          TOTAL CAPITALIZATION. . . . . . . . . . . . . . .     84,447        112,333

OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . .        972          1,259

CURRENT LIABILITIES:
  Short-term Debt - Notes Payable . . . . . . . . . . . . .      8,175         11,750
  Accounts Payable. . . . . . . . . . . . . . . . . . . . .     13,226          9,704
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      4,751          3,420
  Interest Accrued. . . . . . . . . . . . . . . . . . . . .        164            461
  Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . .     23,427          4,963
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      5,311          3,747

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     55,054         34,045

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . .    134,723        138,901

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits . . . . . . . . . . . . .     67,494         70,016
  Deferred Amounts Due to Customers for Income Tax. . . . .     30,404         31,375

          TOTAL REGULATORY LIABILITIES. . . . . . . . . . .     97,898        101,391

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     36,075         31,129

DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . .        154           -   

            TOTAL . . . . . . . . . . . . . . . . . . . . .   $409,323       $419,058
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
<TABLE>
                        AEP GENERATING COMPANY
                       STATEMENTS OF CASH FLOWS
                              (UNAUDITED)
<CAPTION>
                                                                 Nine Months Ended
                                                                   September 30,     
                                                                 1998          1997
                                                                   (in thousands)
<S>                                                            <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .   $  6,422      $  6,685
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . . .     16,229        16,209
    Deferred Federal Income Taxes. . . . . . . . . . . . . .      3,975         3,564
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (2,522)       (2,526)
    Amortization of Deferred Gain on Sale
      and Leaseback - Rockport Plant Unit 2. . . . . . . . .     (4,178)       (4,178)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable. . . . . . . . . . . . . . . . . . .     (1,964)       (1,804)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     (1,870)        7,149
    Accounts Payable . . . . . . . . . . . . . . . . . . . .      3,522        (2,655)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .      1,331         2,292 
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .     18,464        18,464
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .      1,174        (2,044)
        Net Cash Flows From Operating Activities . . . . . .     40,583        41,156

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .     (4,829)       (2,042)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .      2,254          -   
        Net Cash Flows Used For Investing Activities . . . .     (2,575)       (2,042)

FINANCING ACTIVITIES:
  Return of Capital to Parent Company. . . . . . . . . . . .     (3,000)       (2,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .     (3,575)       (9,575)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (25,000)      (20,010)
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .     (6,528)       (5,858)
        Net Cash Flows Used For Financing Activities . . . .    (38,103)      (37,443)

Net Increase (Decrease) in Cash and Cash Equivalents . . . .        (95)        1,671
Cash and Cash Equivalents at Beginning of Period . . . . . .        237           139
Cash and Cash Equivalents at End of Period . . . . . . . . .   $    142      $  1,810


Supplemental Disclosure:
  Cash paid  (received) for interest  net  of capitalized  amounts was $2,508,000 and
  $2,699,000 and for income taxes was $(1,188,000) and $(1,598,000) in 1998 and 1997,
  respectively.
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
                      AEP GENERATING COMPANY
                  NOTES TO FINANCIAL STATEMENTS
                        SEPTEMBER 30, 1998     
                           (UNAUDITED)

1.   GENERAL

     The accompanying unaudited financial statements should be read
in conjunction with the 1997 Annual Report as incorporated in and
filed with the Form 10-K.  In the opinion of management, the
financial statements reflect all adjustments (consisting of only
normal recurring accruals) which are necessary for a fair
presentation of the results of operations and financial condition
for interim periods.

2.   FINANCING ACTIVITIES

     In March 1998 $12.5 million of the 1995 Series A pollution
control revenue bonds due 2025 and $12.5 million of the 1995 Series
B pollution control revenue bonds due 2025 were redeemed.

3.   NEW ACCOUNTING STANDARDS

     Statement of Financial Accounting Standards (SFAS) No. 130
"Reporting Comprehensive Income" was adopted by the Company in the
first quarter of 1998.  SFAS No. 130 established the standards for
reporting and displaying components of "comprehensive income,"
which is the total of net income and all transactions not included
in net income affecting equity except those with shareholders.  For
the quarter and year-to-date periods ended September 30, 1998,
there were no material differences between comprehensive income and
net income.

     In the first quarter of 1998 the Company adopted the American
Institute of Certified Public Accountants' Statement of Position
(SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use." The SOP requires the
capitalization and amortization of certain costs of acquiring or
developing internal use computer software.  Previously the Company
expensed all software acquisition and development costs.  The SOP
must be adopted at the beginning of a fiscal year with no
restatement or retroactive adjustment of prior periods.  The
adoption of the SOP effective January 1, 1998 did not have a
material effect on results of operations, cash flows or financial
condition.

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

            THIRD QUARTER 1998 vs. THIRD QUARTER 1997
                               AND
             YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
     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.
     Net income decreased $0.2 million or 7% for the third quarter
and $0.3 million or 4% for the year-to-date period as a result of
capital returned to the parent company in 1997, May 1998 and August
1998.
     Income statement line items which changed significantly were:

                                   Increase (Decrease)           
                            Third Quarter         Year-to-Date   
                         (in millions)    %   (in millions)    % 

Operating Revenues. . . . .  $ 1.1        2       $(3.1)      (2)
Fuel Expense. . . . . . . .    1.6        6        (0.7)      (1)
Other Operation Expense . .   (0.3)     (14)       (0.8)     (10)
Maintenance Expense . . . .    0.3       14        (1.0)     (10)
Interest Charges. . . . . .   (0.1)      (8)       (0.5)     (17)

     The increase in operating revenues for the third quarter
reflects the recovery through the unit power agreements of higher
operating expenses, primarily fuel expense.  In the year-to-date
period, lower operating expenses and a lower return on common
equity reflecting the return of capital are the primary reasons for
the decline in operating revenues.
     Fuel expense increased in the third quarter reflecting a 7%
increase in generation.  While year-to-date generation increased
5%, a lower average cost of fuel consumed, due to lower coal
prices, produced a reduction in fuel expense.
<PAGE>
<PAGE>
     The decline in other operation expense in both the quarter and
year-to-date periods is primarily due to a decline in
administrative and general expenses reflecting a reduction in
allocated wages and employee benefit costs and a reduction in a
FERC assessment.
     Maintenance expense increased during the quarter due to a rise
in boiler plant repair expenditures, while for the year-to-date
period the reduction in maintenance expense reflects a longer
duration outage in 1997 compared  with 1998's outage.
     The decline in interest charges was due to a reduction in
outstanding long-term debt balances reflecting the redemption of
$20 million in June 1997 and $25 million in March 1998 of pollution
control revenue bonds.
<PAGE>
<PAGE>
<TABLE>
                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                           Three Months Ended       Nine Months Ended
                                             September 30,             September 30,      
                                           1998         1997        1998          1997
                                                         (in thousands)
<S>                                      <C>           <C>        <C>           <C>
OPERATING REVENUES . . . . . . . . . . . $1,312,293    $438,510   $2,689,576    $1,228,044

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    113,059     104,514      322,459       288,773
  Purchased Power. . . . . . . . . . . .    939,595     100,587    1,654,929       261,595
  Other Operation. . . . . . . . . . . .     73,988      60,585      191,297       185,852
  Maintenance. . . . . . . . . . . . . .     30,691      27,615       97,519        79,505
  Depreciation and Amortization. . . . .     36,059      34,568      107,252       102,817
  Taxes Other Than Federal Income Taxes.     29,003      29,544       89,181        89,580
  Federal Income Taxes . . . . . . . . .     18,947      16,317       45,547        45,411

          TOTAL OPERATING EXPENSES . . .  1,241,342     373,730    2,508,184     1,053,533

OPERATING INCOME . . . . . . . . . . . .     70,951      64,780      181,392       174,511
NONOPERATING INCOME (LOSS) . . . . . . .     (5,664)        305       (4,490)          628
INCOME BEFORE INTEREST CHARGES . . . . .     65,287      65,085      176,902       175,139
INTEREST CHARGES . . . . . . . . . . . .     31,841      30,332       95,133        88,524
NET INCOME . . . . . . . . . . . . . . .     33,446      34,753       81,769        86,615
PREFERRED STOCK DIVIDEND REQUIREMENTS. .        675         681        1,822         6,326
EARNINGS APPLICABLE TO COMMON STOCK. . . $   32,771    $ 34,072   $   79,947    $   80,289
                                                              

               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended        Nine Months Ended
                                             September 30,             September 30,     
                                           1998         1997         1998          1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $195,262     $197,471     $207,544      $208,472
NET INCOME . . . . . . . . . . . . . . .   33,446       34,753       81,769        86,615
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   29,729       28,609       89,187        85,827
    Cumulative Preferred Stock . . . . .      567          572        1,499         2,649
  Capital Stock Expense. . . . . . . . .      108          109          323         3,677

BALANCE AT END OF PERIOD . . . . . . . . $198,304     $202,934     $198,304      $202,934

The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                               1998           1997    
                                                                 (in thousands)
ASSETS
<S>                                                         <C>            <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .      $1,959,309     $1,942,325
  Transmission . . . . . . . . . . . . . . . . . . . .       1,117,332      1,079,919
  Distribution . . . . . . . . . . . . . . . . . . . .       1,647,232      1,583,161
  General. . . . . . . . . . . . . . . . . . . . . . .         228,803        207,380
  Construction Work in Progress. . . . . . . . . . . .          77,573         88,261
          Total Electric Utility Plant . . . . . . . .       5,030,249      4,901,046
  Accumulated Depreciation and Amortization. . . . . .       1,958,654      1,869,057

          NET ELECTRIC UTILITY PLANT . . . . . . . . .       3,071,595      3,031,989



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         109,354         34,544



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .           8,467          6,947
  Accounts Receivable. . . . . . . . . . . . . . . . .         161,074        164,657
  Allowance for Uncollectible Accounts . . . . . . . .          (1,590)        (1,333)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .          48,425         47,901
  Materials and Supplies . . . . . . . . . . . . . . .          63,860         57,359
  Accrued Utility Revenues . . . . . . . . . . . . . .          40,630         51,208
  Prepayments and Other. . . . . . . . . . . . . . . .          16,671          6,960

          TOTAL CURRENT ASSETS . . . . . . . . . . . .         337,537        333,699


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         434,704        441,223


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .          37,346         41,975

            TOTAL. . . . . . . . . . . . . . . . . . .      $3,990,536     $3,883,430
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                        September 30,   December 31,
                                                             1998           1997    
                                                               (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. . . . . . . . . . . . . . . . . . .      638,510         613,048
  Retained Earnings. . . . . . . . . . . . . . . . . .      198,304         207,544
          Total Common Shareholder's Equity. . . . . .    1,097,272       1,081,050
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .       19,439          19,747
    Subject to Mandatory Redemption. . . . . . . . . .       22,310          22,310
  Long-term Debt . . . . . . . . . . . . . . . . . . .    1,532,809       1,415,026

          TOTAL CAPITALIZATION . . . . . . . . . . . .    2,671,830       2,538,133

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .      164,715         137,371

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .       19,504          79,509
  Short-term Debt. . . . . . . . . . . . . . . . . . .       61,975         130,300
  Accounts Payable . . . . . . . . . . . . . . . . . .       80,625          96,816
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       43,772          41,549
  Customer Deposits. . . . . . . . . . . . . . . . . .       14,194          13,713
  Interest Accrued . . . . . . . . . . . . . . . . . .       29,841          20,949
  Revenue Refunds Accrued. . . . . . . . . . . . . . .       42,418           3,311
  Other. . . . . . . . . . . . . . . . . . . . . . . .       91,876          68,812

          TOTAL CURRENT LIABILITIES. . . . . . . . . .      384,205         454,959

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      649,472         658,655

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       63,948          67,496

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       56,366          26,816

CONTINGENCIES (Note 6)

            TOTAL. . . . . . . . . . . . . . . . . . .   $3,990,536      $3,883,430
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                  Nine Months Ended
                                                                    September 30,     
                                                                 1998           1997
                                                                    (in thousands)
<S>                                                           <C>             <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $  81,769       $ 86,615
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    108,158        103,796
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     (1,452)        (8,719)
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (3,548)        (3,571)
    Provision for Rate Refunds . . . . . . . . . . . . . . .      9,342          3,083
    Deferred Power Supply Costs (net). . . . . . . . . . . .     25,137         13,951
    Amortization of Deferred Property Taxes. . . . . . . . .     12,940         13,240
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .      3,840         13,458
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     (7,025)        (1,763)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     10,578         18,942
    Prepayments and Other Current Assets . . . . . . . . . .     (9,711)         3,695
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (16,191)        13,188
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .      2,223          1,642
    Interest Accrued . . . . . . . . . . . . . . . . . . . .      8,892         12,285
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . .     39,107         (1,933)
  Payment of Disputed Tax and Interest Related to COLI . . .    (68,316)          -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     22,652        (19,383)
        Net Cash Flows From Operating Activities . . . . . .    218,395        248,526

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (138,297)      (146,039)
  Proceeds from Sale of Property . . . . . . . . . . . . . .        914          4,204
        Net Cash Flows Used For Investing Activities . . . .   (137,383)      (141,835)

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .     25,000         20,000
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    193,431        183,257
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (68,325)        22,825
  Retirement of Cumulative Preferred Stock . . . . . . . . .       (229)      (183,842)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (138,472)       (56,378)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (89,187)       (85,827)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,710)        (5,319)
        Net Cash Flows Used For Financing Activities . . . .    (79,492)      (105,284)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .      1,520          1,407 
Cash and Cash Equivalents at Beginning of Period . . . . . .      6,947          7,260
Cash and Cash Equivalents at End of Period . . . . . . . . .  $   8,467      $   8,667

Supplemental Disclosure:
  Cash paid for  interest net of capitalized  amounts was  $83,359,000 and $73,466,000
  and for income taxes was $38,378,000 and $46,965,000 in 1998 and 1997, respectively.
  Noncash acquisitions under  capital leases were $16,909,000 and  $14,377,000 in 1998
  and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
            APPALACHIAN POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        SEPTEMBER 30, 1998            
                           (UNAUDITED)

1.   GENERAL

         The accompanying unaudited consolidated financial
     statements should be read in conjunction with the 1997 Annual 
     Report as incorporated in and filed with the Form 10-K.  In the
     opinion of management, the financial statements reflect all
     adjustments (consisting of only normal recurring accruals)
     which are necessary for a fair presentation of the results of
     operations and financial condition for interim periods.

2.   RATE MATTER

         In September 1992 the Company implemented, subject to
     refund, an $8.7 million annual rate increase to its wholesale
     customers pending a final order from the Federal Energy
     Regulatory Commission (FERC).  On June 29, 1998 the FERC
     granted an annual rate increase of $3.4 million and required
     a refund including interest of amounts collected in excess of
     the $3.4 million annual increase.  A rehearing of the FERC's
     order has been requested.

         At September 30, 1998, the Company had fully provided for
     the refund obligation plus interest as a current liability.

3.   FINANCING ACTIVITIES

         During the first nine months of 1998, the Company issued
     two series of senior unsecured notes of $100 million each with
     rates of 7.20% and 7.30% due in 2038.

         During the first nine months of 1998, the Company
     reacquired the following first mortgage bonds for $138 million
     including reacquisition premiums:

                                             Principal
                                             Amount
        % Rate        Due Date               Reacquired
                                           (in thousands)
        8.75          2022 - February 1       $29,919
        8.70          2022 - May 22            35,000
        7.95          2002 - March 1           60,000
        8.43          2022 - June 1            12,529

         In June 1998, the Company received a $25 million cash
     capital contribution from its parent which was credited to
     paid-in capital.

<PAGE>
<PAGE>
4.   NEW ACCOUNTING STANDARDS

         Statement of Financial Accounting Standards (SFAS) No. 130
     "Reporting Comprehensive Income" was adopted by the Company in
     the first quarter of 1998.  SFAS No. 130 established the
     standards for reporting and displaying components of
     "comprehensive income," which is the total of net income and
     all transactions not included in net income affecting equity
     except those with shareholders.  For the quarter and year-to-date periods
     ended September 30, 1998, there were no material
     differences between comprehensive income and net income.

         In the first quarter of 1998 the Company adopted the
     American Institute of Certified Public Accountants' Statement
     of Position (SOP) 98-1, "Accounting for the Costs of Computer
     Software Developed or Obtained for Internal Use". The SOP
     requires the capitalization and amortization of certain costs
     of acquiring or developing internal use computer software. 
     Previously the Company expensed software acquisition and
     development costs with the exception of  newly developed
     customer service and billing software costs which were
     capitalized in accordance with an order of the Virginia State
     Corporation Commission.  The SOP must be adopted at the
     beginning of a fiscal year with no restatement or retroactive
     adjustment of prior periods.  The adoption of the SOP effective
     January 1, 1998 did not have a material effect on results of
     operations, cash flows or financial condition.

5.   POWER MARKETING AND TRADING

         During 1998, American Electric Power Service Corporation,
     as agent for the Company and its affiliates in the AEP System
     Power Pool (Power Pool), substantially increased the volume of
     its electricity marketing and trading.  The purpose of the
     power marketing and trading business is to utilize AEP's
     knowledge of the energy markets in order to improve the
     competitiveness of its generation business and contribute to
     net income.  Revenues and expenses from these activities are
     shared by the Power Pool members based on their relative peak
     demands.

         The power marketing and trading business involves the
     marketing of power under physical forward contracts at fixed
     and variable prices and the trading of options, futures, swaps
     and other financial derivative contracts at both fixed and
     variable prices.  Most contracts represent physical forward
     electricity marketing contracts for the purchase and sale of
     electricity in the Power Pool's traditional marketing area
     which are recorded as operating revenues and purchased power
     expense  when the contracts settle.  At September 30, 1998, the
     Power Pool had open marketing contracts, not on the balance
     sheet, in its traditional marketing area through the year 2004
     to sell electricity with a notional value of approximately $1.1
     billion and to purchase electricity with a notional value of
     approximately $1.1 billion.  The Company's share of these 

<PAGE>
     notional values is approximately $320 million.

         The Power Pool has also purchased and sold electricity
     options, futures, and swaps, and entered into forward purchase
     and sale contracts for the future delivery or receipt of
     electricity outside its traditional marketing area.  These
     transactions represent non-regulated trading activities that
     are marked-to-market and recorded in nonoperating income.  At
     September 30, 1998, the Company's share of the unrealized mark-to-market
     gains and losses from such trading contracts are
     reported as assets and liabilities, respectively.  At September
     30, 1998, the Power Pool had open marketing contracts outside
     its traditional marketing area through the year 2008 to sell
     electricity with a notional value of approximately $230 million
     and to purchase electricity with a notional value of
     approximately $145 million.  The Company's share of these
     notional values is approximately $70 million for sales and
     approximately $45 million for purchases.

         Dependent on future electricity market conditions these
     activities could produce material income or losses in future
     periods.

6.   CONTINGENCIES

     Taxes

         As discussed in Note 9, "Federal Income Taxes" of the Notes
     to Consolidated Financial Statements in the 1997 Annual Report,
     the Internal Revenue Service (IRS) agents auditing the AEP
     System's consolidated federal income tax returns requested a
     ruling from their National Office that certain interest
     deductions relating to corporate owned life insurance (COLI)
     claimed by the Company should not be allowed.  As a result of
     a suit filed in United States District Court (discussed below)
     this request for ruling has been withdrawn.  Adjustments have
     been or will be proposed by the IRS disallowing COLI interest
     deductions for taxable years 1991-96.  A disallowance of the
     COLI interest deduction through September 30, 1998 would reduce
     earnings by approximately $77 million (including interest). 
     The Company has made no provision for any possible adverse
     earnings impact from this matter.

         In order to resolve this issue without further delay, on
     March 24, 1998, the Company filed suit against the United
     States in the United States District Court for the Southern
     District of Ohio.  Management believes that it has a
     meritorious position and will vigorously pursue this lawsuit. 
     In July 1998, the Company made a payment of taxes and interest
     attributable to COLI interest deductions for taxable years
     1991-96 to avoid the potential assessment by the IRS of any
     additional above market rate interest on the contested amount. 
     In September 1998 the Company made an additional payment for
     the 1997 tax year.  The payments were included on the balance
     sheet in other property and investments pending the resolution 

<PAGE>
     of this matter.  The Company will seek refund, either   
  administratively or through litigation, of all amounts paid. 
  In the event the resolution of this matter is unfavorable, it   
 will have a material adverse impact on results of operations
     and cash flows.

     Revised Air Quality Standards

         The United States Environmental Protection Agency (Federal
     EPA) published in October 1997 a proposed nitrogen oxides (NOx)
     emissions reduction rule which called for new state
     implementation plans (SIPs).  SIPs are a procedural method used
     by each state to comply with Federal EPA rules.  Eight
     northeastern states also filed petitions in 1997 with Federal
     EPA claiming NOx emissions from plants in midwestern states
     prevent them from complying with air quality standards.

         On September 24, 1998, Federal EPA issued final rules which
     require reductions in NOx emissions in 22 eastern states,
     including the states in which the Company's generating plants
     are located.  The implementation of the final rules would be
     achieved through the revision of SIPs by September 1999 that,
     by the year 2003, anticipate the imposition of a NOx reduction
     on utility sources of approximately 85% below 1990 emission
     levels.  On October 30, 1998, a number of utilities, including
     the Company and its affiliates in the AEP System, filed a
     petition in the U.S. Court of Appeals for the District of
     Columbia Circuit seeking a review of the final rules.

         Should the states fail to adopt the required revisions to
     their SIPs within one year of the date of the final rules
     (September 24, 1999), Federal EPA has proposed to implement a
     federal plan to accomplish the NOx reductions.  Federal EPA
     also proposed the approval of portions of the petitions filed
     by the eight northeastern states that would result in
     imposition of NOx emission reductions on utility and industrial
     sources.  These reductions are substantially the same as those
     required by the final rules and could be adopted by Federal EPA
     in the event the states fail to implement SIPs in accordance
     with the final rules.

         Based on initial studies, preliminary estimates indicate
     that compliance costs could result in capital expenditures of
     approximately $325 million.  Compliance costs can not be
     estimated with certainty and the actual costs incurred to
     comply could be significantly different from the preliminary
     estimate depending upon the compliance alternatives selected
     to achieve reductions in NOx emissions.  Unless such costs are
     recovered from customers, they would have a material adverse
     effect on results of operations, cash flows and possibly
     financial condition.
<PAGE>
     
<PAGE>
     Other

         The Company continues to be involved in certain other
     matters discussed in its 1997 Annual Report.
<PAGE>
<PAGE>
            APPALACHIAN POWER COMPANY AND SUBSIDIARIES
  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                     AND FINANCIAL CONDITION                   
            THIRD QUARTER 1998 vs. THIRD QUARTER 1997
                               AND
             YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
RESULTS OF OPERATIONS
     Despite an increase in revenues net of fuel and purchased power
expenses (net revenues) of $26.3 million for the third quarter and
$34.5 million for the year-to-date period due to an increase in
weather related retail sales and wholesale power marketing and
trading transactions within AEP's traditional marketing area, net
income decreased $1.3 million or 4% for the quarter and $4.8
million or 6% for the year-to-date period.  The decline in net
income was primarily due to an increase in operating expenses other
than fuel and purchased power, losses on certain non-regulated
energy trades outside of the Company's marketing area, an increase
in interest charges and the recordation of provisions for revenue
refunds, net of tax. 
     The significant changes in income statement line items and net
revenues were:
                                   Increase (Decrease)          
                             Third Quarter       Year-to-Date   
                          (in millions)   %   (in millions)   % 

Operating Revenues . . . .   $873.8     199      $1,461.5   119
Fuel Expense . . . . . . .      8.5       8          33.7    12
Purchased Power Expense. .    839.0     N.M.      1,393.3   N.M.
  Net Revenues . . . . . .     26.3                  34.5
Other Operation Expense. .     13.4      22           5.4     3
Maintenance Expense. . . .      3.1      11          18.0    23
Depreciation and
  Amortization . . . . . .      1.5       4           4.4     4
Federal Income Taxes . . .      2.6      16           0.1    -
Nonoperating Income. . . .     (6.0)    N.M.         (5.1)  N.M.
Interest Charges . . . . .      1.5       5           6.6     7

N.M. = Not Meaningful

     Operating revenues increased significantly in both the third
quarter and the year-to-date periods due predominantly to increased
retail and wholesale sales.  The increase in retail revenues can be
attributed to increased energy sales to residential and commercial
customers  reflecting  warmer  spring  and summer weather in 1998. 
<PAGE>
Revenues from wholesale customers increased significantly
reflecting growth in power marketing and trading transactions.
     The increases in fuel expense for the quarter and year-to-date
periods were primarily due to increased coal fired generation to
meet the increased demand.
     Purchased power expense increased primarily as a result of the
growth in power marketing and trading activities.
      The increase in other operation expense was mainly due to
costs related to the increase in sales and employee incentive pay
accruals.
     Maintenance expense increased as a result of an increase in
planned expenditures to maintain transmission and distribution
right-of-ways and, for the year-to-date period, costs for repair
and restoration of service caused by two severe snowstorms.
     The increase in depreciation and amortization expense is mainly
due to additional investment in depreciable plant reflecting
improvements to the transmission and distribution system.
     In the third quarter federal income tax expense attributable
to operations increased primarily due to an increase in pre-tax
operating income.
     The decrease in nonoperating income is primarily due to losses
on certain power marketing and trading transactions.  These
transactions, which are marked-to-market and described in footnote
5, represent non-regulated trading activities outside the Company's
traditional marketing area.  Although losses were incurred on these
non-regulated energy trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.
     Interest charges for the quarter and year-to-date periods
increased as a result of the accrual of interest on a revenue
refund to wholesale customers under the terms of a final rate order
and an increase in long-term debt outstanding.
FINANCIAL CONDITION
     Total plant and property additions including capital leases for
the first nine months of 1998 were $155 million.
<PAGE>
<PAGE>
     During the first nine months of 1998, the Company issued two
series of senior unsecured notes of $100 million each with rates of
7.20% and 7.30% due in 2038 and redeemed $137 million principal
amount of first mortgage bonds with interest rates from 7.95% to
8.75%.  Short-term debt decreased by $68 million from year-end
balances.  In June 1998, the Company received a $25 million cash
capital contribution from its parent which was credited to paid-in
capital.
REVISED AIR QUALITY STANDARDS
     The United States Environmental Protection Agency (Federal EPA)
published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state implementation
plans (SIPs).  SIPs are a procedural method used by each state to
comply with Federal EPA rules.  Eight northeastern states also
filed petitions in 1997 with Federal EPA claiming NOx emissions
from plants in midwestern states prevent them from complying with
air quality standards.
     On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states, including
the states in which the Company's generating plants are located. 
The implementation of the final rules would be achieved through the
revision of SIPs by September 1999 that, by the year 2003,
anticipate the imposition of  a NOx reduction on utility sources of
approximately 85% below 1990 emission levels.  On October 30, 1998,
a number of utilities, including the Company and its affiliates in
the AEP System, filed a petition in the U.S. Court of Appeals for
the District of Columbia Circuit seeking a review of the final
rules.
     Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions.  Federal EPA also proposed the
approval of portions of the petitions filed by the eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources.  These reductions are
substantially the same as those required by the final rules and
could be adopted by Federal EPA in the event the states fail to 

<PAGE>
implement SIPs in accordance with the final rules.
     Based on initial studies, preliminary estimates indicate that
compliance costs could result in capital expenditures of
approximately $325 million.  Compliance costs can not be estimated
with certainty and the actual costs incurred to comply could be
significantly different from the preliminary estimate depending
upon the compliance alternatives selected to achieve reductions in
NOx emissions.  Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations,
cash flows and possibly financial condition.
COMPUTER ISSUE - YEAR 2000
     On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems were 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-Year
2000 ready programs.

     Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Year 2000-related failures and repair such failures if they occur. 
This includes both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), 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 Year 2000 readiness.
     Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system. 
AEP, along with other electric utilities in North America,
regularly submits information to the North American Electric 

<PAGE>
Reliability Council (NERC) as part of NERC's Year 2000 readiness
program.  NERC then publicly reports summary information to the
U.S. Department of Energy regarding the Year 2000 readiness of
electric utilities.  In 1999 AEP plans to participate in two
NERC-sponsored coordinated electric industry Year 2000 readiness
drills.  The first NERC report, dated September 17, 1998 and titled
Preparing the Electric Power Systems of North America for
Transition to the Year 2000-A Status Report and Work Plan, states
that: "Mission critical systems and components are to be made Y2K
Ready by June 30, 1999."  In addition, the report indicates that:
"While many organizations are on track to meet these targets, many
others need to accelerate project plans and resources."  In
response to the report, the Company has accelerated its Year 2000
readiness date for mission critical and high priority systems and
components from September 30, 1999 to June 30, 1999.
     Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems.  Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.
     Various state regulatory commissions are also reviewing the
Year 2000 readiness of electric utilities subject to their
jurisdiction.

     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,
communications, and the physical generation and delivery of energy;
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>
<PAGE>
     The following chart shows our progress toward becoming ready
for the Year 2000 as of September 30, 1998:
                             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%         11/30/1998    86%
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     2%
replacing or retiring                     60%
those mission critical and                        
high priority digital-based
systems with problems                     Client
processing dates past the                 Server:
Year 2000. Testing these                  1%
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
September 30, 1998, the Company has spent $4 million on the Year
2000 project and, estimates spending an additional $12 million to
$16 million to achieve Year 2000 readiness.  Most Year 2000 costs
are software, IT consultant and salary-related 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 Year 2000 ready is not expected to have a material impact
on the Company's results of operations, cash flows or financial
condition.
<PAGE>
<PAGE>
     Risks of the Company's Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Year 2000 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.

     In addition, although as discussed 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, Year 2000-related issues may materially adversely
affect AEP.

     Company's Contingency Plans - The Company intends to establish
contingency plans on a case-by-case basis to address alternatives
if Year 2000 failures of automatic systems and equipment occur as
part of its Year 2000 readiness program.  The contingency plans
will be based upon a risk analysis process and will be developed by
the fourth quarter of 1999.  These plans will build upon disaster
recovery, system restoration, and contingency planning that we now 

<PAGE>
have in place.  We have begun the contingency planning process,
including the review of NERC's Contingency Planning Guide.  The
Company plans to submit a draft of its contingency plans to NERC as
part of NERC's review of drafts of regional and individual electric
utility contingency plans in 1999.

     Forward-Looking Statements - This description of Year 2000
problems, the consequences of Year 2000 failures and the estimated
costs of, and timetable for, becoming Year 2000 ready constitute
"forward looking statements" as defined in the Private Securities
Litigation Reform Act of 1995.  Such statements are based on
management's beliefs as well as assumptions made by, and
information currently available to, management.  Investors are
cautioned that such statements and estimates could differ
materially from actual results because of factors referred to
specifically in connection with such forward-looking statements
and, in addition, the following other factors, among others:
     *   Continuing availability of experienced consultants and IT
         personnel and related resources
     *   Ability of third parties to complete their Year 2000
         remediations on a timely basis and accuracy of
         representations made by such third parties concerning
         their Year 2000 readiness
     *   Ability of the Company to identify and implement
         contingency plans.

TAXES
     As discussed in Note 9, "Federal Income Taxes" of the Notes to
Consolidated Financial Statements in the 1997 Annual Report, the
Internal Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from
their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company should
not be allowed.  As a result of a suit filed in United States
District Court (discussed below) this request for ruling has been
withdrawn.  Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions for taxable years 1991-96.  A 

<PAGE>
disallowance of the COLI interest deduction through September 30,
1998 would reduce earnings by approximately $77 million (including
interest).  The Company has made no provision for any possible
adverse earnings impact from this matter.
     In order to resolve this issue without further delay, on March
24, 1998, the Company filed suit against the United States in the
United States District Court for the Southern District of Ohio. 
Management believes that it has a meritorious position and will
vigorously pursue this lawsuit.  In July 1998, the Company made a
payment of taxes and interest attributable to COLI interest
deductions for taxable years 1991-96 to avoid the potential
assessment by the IRS of any additional above market rate interest
on the contested amount.  In September 1998 the Company made an
additional payment for the 1997 tax year.  The payments were
included on the balance sheet in other property and investments
pending the resolution of this matter.  The Company will seek
refund, either administratively or through litigation, of all
amounts paid.  In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations and cash flows.
POWER MARKETING AND TRADING
     During 1998, American Electric Power Service Corporation, as
agent for the Company and its affiliates in the AEP System Power
Pool (Power Pool), substantially increased the volume of its
electricity marketing and trading.  The purpose of the power
marketing and trading business is to utilize AEP's knowledge of the
energy markets in order to improve the competitiveness of its
generation business and contribute to net income.  Revenues and
expenses from these activities are shared by the Power Pool members
based on their relative peak demands.
     The power marketing and trading business involves the marketing
of power under physical forward contracts at fixed and variable
prices and the trading of options, futures, swaps and other
financial derivative contracts at both fixed and variable prices. 
Most contracts represent physical forward electricity marketing
contracts for the purchase and sale of electricity in the Power
Pool's traditional marketing area which are recorded as operating 

<PAGE>
revenues and purchased power expense  when the contracts settle. 
At September 30, 1998, the Power Pool had open marketing contracts,
not on the balance sheet, in its traditional marketing area through
the year 2004 to sell electricity with a notional value of
approximately $1.1 billion and to purchase electricity with a
notional value of approximately $1.1 billion.  The Company's share
of these notional values is approximately $320 million.
     The Power Pool has also purchased and sold electricity options,
futures, and swaps, and entered into forward purchase and sale
contracts for the future delivery or receipt of electricity outside
its traditional marketing area.  These transactions represent non-regulated
trading activities that are marked-to-market and recorded
in nonoperating income.  At September 30, 1998, the Company's share
of the unrealized mark-to-market gains and losses from such trading
contracts are reported as assets and liabilities, respectively.  At
September 30, 1998, the Power Pool had open marketing contracts
outside its traditional marketing area through the year 2008 to
sell electricity with a notional value of approximately $230
million and to purchase electricity with a notional value of
approximately $145 million.  The Company's share of these notional
values is approximately $70 million for sales and approximately $45
million for purchases.
     Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
<PAGE>
<PAGE>
<TABLE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                          Three Months Ended         Nine Months Ended
                                             September 30,              September 30,    
                                           1998         1997         1998          1997
                                                         (in thousands)
<S>                                      <C>          <C>         <C>            <C>
OPERATING REVENUES . . . . . . . . . . . $843,007     $313,024    $1,711,773     $841,294

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   49,693       52,269       143,533      134,198
  Purchased Power. . . . . . . . . . . .  561,812       54,444       972,535      138,278
  Other Operation. . . . . . . . . . . .   59,478       46,505       150,843      132,256
  Maintenance. . . . . . . . . . . . . .   13,932       17,535        43,128       50,602
  Depreciation . . . . . . . . . . . . .   22,760       22,784        68,454       67,800
  Amortization of Zimmer Plant
    Phase-in Costs . . . . . . . . . . .     -            -             -          15,744
  Taxes Other Than Federal Income Taxes.   29,295       29,861        86,921       89,484
  Federal Income Taxes . . . . . . . . .   31,774       24,731        69,716       57,639
          TOTAL OPERATING EXPENSES . . .  768,744      248,129     1,535,130      686,001

OPERATING INCOME . . . . . . . . . . . .   74,263       64,895       176,643      155,293
NONOPERATING INCOME (LOSS) . . . . . . .   (2,337)         658        (1,109)       2,018
INCOME BEFORE INTEREST CHARGES . . . . .   71,926       65,553       175,534      157,311
INTEREST CHARGES . . . . . . . . . . . .   19,635       20,065        58,856       59,069
NET INCOME . . . . . . . . . . . . . . .   52,291       45,488       116,678       98,242
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      532          532         1,598        1,909
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 51,759     $ 44,956    $  115,080     $ 96,333

                                                               

               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended         Nine Months Ended
                                             September 30,              September 30,    
                                           1998         1997         1998          1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $160,171     $111,953    $138,172       $ 99,582
NET INCOME . . . . . . . . . . . . . . .   52,291       45,488     116,678         98,242
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   20,661       19,671      61,983         59,013
    Cumulative Preferred Stock . . . . .      437          437       1,312          1,312
  Capital Stock Expense. . . . . . . . .       95           95         286            261

BALANCE AT END OF PERIOD . . . . . . . . $191,269     $137,238    $191,269       $137,238

The common stock of the Company is wholly owned by American Electric Power Company, Inc.
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1998            1997    
                                                                 (in thousands)
ASSETS
<S>                                                        <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $1,520,079      $1,521,381
  Transmission . . . . . . . . . . . . . . . . . . . .        338,743         336,446
  Distribution . . . . . . . . . . . . . . . . . . . .        927,225         926,178
  General. . . . . . . . . . . . . . . . . . . . . . .        122,532         138,041
  Construction Work in Progress. . . . . . . . . . . .        120,161          54,064
          Total Electric Utility Plant . . . . . . . .      3,028,740       2,976,110
  Accumulated Depreciation . . . . . . . . . . . . . .      1,118,654       1,074,588

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      1,910,086       1,901,522



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         67,941          33,235



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          6,505          12,626
  Accounts Receivable (net). . . . . . . . . . . . . .        129,936         110,969
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         15,856          19,549
  Materials and Supplies . . . . . . . . . . . . . . .         30,442          27,628
  Accrued Utility Revenues . . . . . . . . . . . . . .         50,537          51,765
  Prepayments. . . . . . . . . . . . . . . . . . . . .         34,219          30,397
 
          TOTAL CURRENT ASSETS . . . . . . . . . . . .        267,495         252,934


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        351,571         359,481


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         21,658          66,688


            TOTAL. . . . . . . . . . . . . . . . . . .     $2,618,751      $2,613,860
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1998            1997    
                                                                 (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. . . . . . . . . . . . . . . . . . .        572,397         572,112
  Retained Earnings. . . . . . . . . . . . . . . . . .        191,269         138,172
          Total Common Shareholder's Equity. . . . . .        804,692         751,310
  Cumulative Preferred Stock - Subject to               
    Mandatory Redemption . . . . . . . . . . . . . . .         25,000          25,000
  Long-term Debt . . . . . . . . . . . . . . . . . . .        959,651         887,850
                                                        
          TOTAL CAPITALIZATION . . . . . . . . . . . .      1,789,343       1,664,160
                                                        
                                                        
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .         46,028          42,271
                                                        
CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .           -             81,750
  Short-term Debt. . . . . . . . . . . . . . . . . . .         55,350          66,600
  Accounts Payable . . . . . . . . . . . . . . . . . .         52,053          71,287
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         95,052         131,107
  Interest Accrued . . . . . . . . . . . . . . . . . .         24,227          14,198
  Other. . . . . . . . . . . . . . . . . . . . . . . .         42,908          28,972
                                                        
          TOTAL CURRENT LIABILITIES. . . . . . . . . .        269,590         393,914
                                                        
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .        436,168         433,593
                                                        
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .         50,272          52,934
                                                        
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .         27,350          26,988

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .     $2,618,751      $2,613,860
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                 Nine Months Ended
                                                                    September 30,     
                                                                1998            1997
                                                                   (in thousands)
<S>                                                           <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 116,678      $  98,242
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . .     68,617         67,978
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     12,398           (741)
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (2,662)        (2,705)
    Deferred Fuel Costs (net). . . . . . . . . . . . . . . .    (10,169)        (4,089)
    Amortization of Zimmer Plant Operating Expenses and
      Carrying Charges . . . . . . . . . . . . . . . . . . .       -            15,936
    Amortization of Deferred Property Taxes. . . . . . . . .     48,775         48,601
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (18,967)       (52,786)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .        879          1,364
    Accrued Utility Revenues . . . . . . . . . . . . . . . .      1,228        (14,057)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (19,234)         2,008
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (36,055)       (50,645)
    Interest Accrued . . . . . . . . . . . . . . . . . . . .     10,029         12,707
    Other Current Assets and Current Liabilities . . . . . .     10,114          5,350
  Payment of Disputed Tax and Interest Related to COLI . . .    (37,243)          -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     16,799         (9,827)
        Net Cash Flows From Operating Activities . . . . . .    161,187        117,336

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .    (84,178)       (82,696)
  Proceeds from Sale of Property and Other . . . . . . . . .      2,546          1,586
        Net Cash Flows Used For Investing Activities . . . .    (81,632)       (81,110)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    111,075         38,574
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (11,250)        42,925
  Retirement of Cumulative Preferred Stock . . . . . . . . .       -           (52,953)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (122,206)          -
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (61,983)       (59,013)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,312)        (2,297)
        Net Cash Flows Used For Financing Activities . . . .    (85,676)       (32,764)

Net Increase (Decrease) in Cash and Cash Equivalents . . . .     (6,121)         3,462
Cash and Cash Equivalents at Beginning of Period . . . . . .     12,626          9,134
Cash and Cash Equivalents at End of Period . . . . . . . . .  $   6,505      $  12,596

Supplemental Disclosure:
  Cash paid for  interest net  of capitalized amounts was  $46,014,000 and $43,341,000
  and for income taxes was $27,254,000 and $50,609,000 in 1998 and 1997, respectively.
  Noncash acquisitions  under capital leases  were $10,029,000 and  $6,583,000 in 1998
  and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
         COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        SEPTEMBER 30, 1998               
                           (UNAUDITED)

1.   GENERAL

         The accompanying unaudited consolidated financial
     statements should be read in conjunction with the 1997 Annual
     Report as incorporated in and filed with the Form 10-K.  In the
     opinion of management, the financial statements reflect all
     adjustments (consisting of only normal recurring accruals)
     which are necessary for a fair presentation of the results of
     operations and financial condition for interim periods.

2.   FINANCING ACTIVITIES

         During the first nine months of 1998 the Company redeemed
     $57 million of 9.15% and $25 million of 7.00% first mortgage
     bonds at maturity and $40 million of 7.95% first mortgage bonds
     due 2002 and issued $52 million of 6.51% and $60 million of
     6.55% senior unsecured notes due in 2008.

3.   NEW ACCOUNTING STANDARDS

         Statement of Financial Accounting Standards (SFAS) No. 130
     "Reporting Comprehensive Income" was adopted by the Company in
     the first quarter of 1998.  SFAS No. 130 established the
     standards for reporting and displaying components of
     "comprehensive income," which is the total of net income and
     all transactions not included in net income affecting equity
     except those with shareholders.  For the quarter and year-to-date periods
     ended September 30, 1998, there were no material
     differences between comprehensive income and net income.

         In the first quarter of 1998 the Company adopted the
     American Institute of Certified Public Accountants' Statement
     of Position (SOP) 98-1, "Accounting for the Costs of Computer
     Software Developed or Obtained for Internal Use." The SOP
     requires the capitalization and amortization of certain costs
     of acquiring or developing internal use computer software. 
     Previously the Company expensed all software acquisition and
     development costs.  The SOP must be adopted at the beginning
     of a fiscal year with no restatement or retroactive adjustment
     of prior periods.  The adoption of the SOP effective January
     1, 1998 did not have a material effect on results of
     operations, cash flows or financial condition.

4.   POWER MARKETING AND TRADING

         During 1998, American Electric Power Service Corporation,
     as agent for the Company and its affiliates in the AEP System
     Power Pool (Power Pool), substantially increased the volume of
     its electricity marketing and trading.  The purpose of the
     power marketing and trading business is to utilize AEP's 

<PAGE>
     knowledge of the energy markets in order to improve the
     competitiveness of its generation business and contribute to
     net income.  Revenues and expenses from these activities are
     shared by the Power Pool members based on their relative peak
     demands.

         The power marketing and trading business involves the
     marketing of power under physical forward contracts at fixed
     and variable prices and the trading of options, futures, swaps
     and other financial derivative contracts at both fixed and
     variable prices.  Most contracts represent physical forward
     electricity marketing contracts for the purchase and sale of
     electricity in the Power Pool's traditional marketing area
     which are recorded as operating revenues and purchased power
     expense  when the contracts settle.  At September 30, 1998, the
     Power Pool had open marketing contracts, not on the balance
     sheet, in its traditional marketing area through the year 2004
     to sell electricity with a notional value of approximately $1.1
     billion and to purchase electricity with a notional value of
     approximately $1.1 billion.  The Company's share of these
     notional values is approximately $190 million.

         The Power Pool has also purchased and sold electricity
     options, futures, and swaps, and entered into forward purchase
     and sale contracts for the future delivery or receipt of
     electricity outside the traditional marketing area.  These
     transactions represent non-regulated trading activities that
     are marked-to-market and recorded in nonoperating income.  At
     September 30, 1998, the Company's share of the unrealized mark-to-market
     gains and losses from such trading contracts  are
     reported as assets and liabilities, respectively.  At September
     30, 1998, the Power Pool had open marketing contracts outside
     its traditional marketing area through the year 2008 to sell
     electricity with a notional value of approximately $230 million
     and to purchase electricity with a notional value of
     approximately $145 million.  The Company's share of these
     notional values is approximately $40 million for sales and
     approximately $25 million for purchases.

         Dependent on future electricity market conditions these
     activities could produce material income or losses in future
     periods.

5.   CONTINGENCIES

     Taxes

         As discussed in Note 8, "Federal Income Taxes" of the Notes
     to Consolidated Financial Statements in the 1997 Annual Report,
     the Internal Revenue Service (IRS) agents auditing the AEP
     System's consolidated federal income tax returns requested a
     ruling from their National Office that certain interest
     deductions relating to corporate owned life insurance (COLI)
     claimed by the Company should not be allowed.  As a result of
     a suit filed in United States District Court (discussed below) 

<PAGE>
     this request for ruling has been withdrawn.  Adjustments have
     been or will be proposed by the IRS disallowing COLI interest
     deductions for taxable years 1991-96.  A disallowance of COLI
     interest deductions through September 30, 1998 would reduce
     earnings by approximately $42 million (including interest). 
     The Company has made no provision for any possible adverse
     earnings impact from this matter.

         In order to resolve this issue without further delay, on
     March 24, 1998, the Company filed suit against the United
     States in the United States District Court for the Southern
     District of Ohio.  Management believes that it has a
     meritorious position and will vigorously pursue this lawsuit. 
     In July 1998, the Company made a payment of taxes and interest
     attributable to COLI interest deductions for taxable years
     1991-96 to avoid the potential assessment by the IRS of any
     additional above market rate interest on the contested amount. 
     In September 1998, the Company made an additional payment for
     the 1997 tax year.  The payments were included on the balance
     sheet in other property and investments pending the resolution
     of this matter.  The Company will seek refund, either
     administratively or through litigation, of all amounts paid. 
     In the event the resolution of this matter is unfavorable, it
     will have a material adverse impact on results of operations
     and cash flows.

     Revised Air Quality Standards

         The United States Environmental Protection Agency (Federal
     EPA) published in October 1997 a proposed nitrogen oxides (NOx)
     emissions reduction rule which called for new state
     implementation plans (SIPs).  SIPs are a procedural method used
     by each state to comply with Federal EPA rules.  Eight
     northeastern states also filed petitions in 1997 with Federal
     EPA claiming NOx emissions from plants in midwestern states
     prevent them from complying with air quality standards.

         On September 24, 1998, Federal EPA issued final rules which
     require reductions in NOx emissions in 22 eastern states,
     including the states in which the Company's generating plants
     are located.  The implementation of the final rules would be
     achieved through the revision of SIPs by September 1999 that,
     by the year 2003, anticipate the imposition of a NOx reduction
     on utility sources of approximately 85% below 1990 emission
     levels.  On October 30, 1998, a number of utilities, including
     the Company and its affiliates in the AEP System, filed a
     petition in the U.S. Court of Appeals for the District of
     Columbia Circuit seeking a review of the final rules.

         Should the states fail to adopt the required revisions to
     their SIPs within one year of the date of the final rules
     (September 24, 1999), Federal EPA has proposed to implement a
     federal plan to accomplish the NOx reductions.  Federal EPA
     also proposed the approval of portions of the petitions filed
     by the eight northeastern states that would result in 

<PAGE>
     imposition of NOx emission reductions on utility and industrial
     sources.  These reductions are substantially the same as those
     required by the final rules and could be adopted by Federal EPA
     in the event the states fail to implement SIPs in accordance
     with the final rules.

         Based on initial studies, preliminary estimates indicate
     that compliance costs could result in capital expenditures of
     approximately $140 million.  Compliance costs can not be
     estimated with certainty and the actual costs incurred to
     comply could be significantly different from the preliminary
     estimate depending upon the compliance alternatives selected
     to achieve reductions in NOx emissions.  Unless such costs are
     recovered from customers, they would have a material adverse
     effect on results of operations, cash flows and possibly
     financial condition.

     Other

         The Company continues to be involved in certain other
     matters discussed in its 1997 Annual Report.

<PAGE>
<PAGE>
         COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
     MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
            THIRD QUARTER 1998 vs. THIRD QUARTER 1997
                               AND
             YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
     Net income increased $6.8 million or 15% for the third quarter
and $18.4 million or 19% for the year-to-date period primarily due
to increased sales to retail customers reflecting warmer summer
weather and growth in wholesale power marketing and trading
activities.
     The significant changes in income statement line items and net
revenues were:
                                    Increase (Decrease)          
                             Third Quarter        Year-to-Date   
                           (in millions)   %   (in millions)   % 

Operating Revenues. . . . .    $530.0    169       $870.5    103
Fuel Expense. . . . . . . .      (2.6)    (5)         9.3      7
Purchased Power Expense . .     507.4    N.M.       834.3    N.M.
  Net Revenues. . . . . . .      25.2                26.9
Other Operation Expense . .      13.0     28         18.6     14
Maintenance Expense . . . .      (3.6)   (21)        (7.5)   (15)
Amortization of Zimmer
  Plant Phase-in Costs. . .       -       -         (15.7)   N.M.
Federal Income Taxes. . . .      7.0      28         12.1     21
Nonoperating Income . . . .     (3.0)    N.M.        (3.1)  (155)

N.M. = Not Meaningful

     Operating revenues increased significantly in both the third
quarter and the year-to-date period due predominantly to increased
retail and wholesale sales.  The increase in retail revenues
resulted from increased sales to residential customers reflecting
warmer summer weather in 1998.  Revenues from wholesale customers
increased reflecting substantial increases in power marketing and
trading transactions.
     The increase in fuel expense for the year-to-date period was
due to an increase in generation reflecting the increase in demand
for electricity.
     Purchased power expense increased primarily as a result of
increased power marketing and trading activities.
<PAGE>
<PAGE>
     Net revenues increased $25.2 million in the third quarter and
$26.9 million in the year-to-date period due to increased retail
sales reflecting warmer summer weather and the successful trading
of wholesale energy in a volatile market.
     The increase in other operation expense was mainly due to costs
related to the increase in sales including increased emission
allowance consumption, transmission costs and employee pensions and
benefits expense.
     Maintenance expense decreased due to the effect of scheduled
power plant maintenance outages in 1997 and a decline in overhead
line maintenance expenditures in 1998.  In 1997 two generating
units underwent a scheduled outage for inspection and repairs while
in 1998 only one unit had a scheduled outage for inspection and
repairs.  Expenditures for overhead line maintenance declined in
1998 as a result of lower expenditures for tree trimming and repair
of conductors and pole attachments.
     The reduction in the amortization of deferred Zimmer Plant
phase-in costs reflects the completion of the surcharge recovery
plan and the amortization of the original deferral in June 1997. 
The cessation of the amortization did not affect net income since
the amortization was being recovered in revenues through a
surcharge which terminated with the completion of the amortization.
     Federal income taxes attributable to operations increased
primarily due to an increase in pre-tax operating income.
     The decrease in nonoperating income is primarily due to losses
on certain power marketing and trading transactions.  These
transactions, which are marked-to-market and described in footnote
4, represent non-regulated trading activities outside the Company's
traditional marketing area.  Although losses were incurred on these
non-regulated energy trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.

<PAGE>
<PAGE>
<TABLE>
              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                          Three Months Ended          Nine Months Ended
                                             September 30,              September 30,    
                                           1998        1997           1998         1997
                                                         (in thousands)
<S>                                      <C>         <C>           <C>         <C>
OPERATING REVENUES . . . . . . . . . . . $945,474    $362,058      $1,978,907  $1,023,879

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   51,014      62,275         133,768     176,051
  Purchased Power. . . . . . . . . . . .  625,294      54,043       1,126,651     124,216
  Other Operation. . . . . . . . . . . .   97,985      80,399         257,268     240,310
  Maintenance. . . . . . . . . . . . . .   39,107      29,408          99,444      85,103
  Depreciation and Amortization. . . . .   36,380      35,271         108,407     105,395
  Amortization of Rockport Plant Unit 1
    Phase-in Plan Deferrals. . . . . . .     -          2,999            -         10,821
  Taxes Other Than Federal Income Taxes.   16,514      15,781          49,011      49,657
  Federal Income Taxes . . . . . . . . .   20,541      21,433          52,157      61,843
          TOTAL OPERATING EXPENSES . . .  886,835     301,609       1,826,706     853,396
OPERATING INCOME . . . . . . . . . . . .   58,639      60,449         152,201     170,483
NONOPERATING INCOME (LOSS) . . . . . . .   (2,404)        499             191       1,464
INCOME BEFORE INTEREST CHARGES . . . . .   56,235      60,948         152,392     171,947
INTEREST CHARGES . . . . . . . . . . . .   17,544      15,857          51,421      48,689
NET INCOME . . . . . . . . . . . . . . .   38,691      45,091         100,971     123,258
PREFERRED STOCK DIVIDEND REQUIREMENTS. .    1,208       1,219           3,627       4,544
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 37,483    $ 43,872      $   97,344    $118,714

                                                              

               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended          Nine Months Ended
                                             September 30,              September 30,   
                                           1998        1997           1998        1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $279,943    $285,783       $278,814    $269,071
NET INCOME . . . . . . . . . . . . . . .   38,691      45,091        100,971     123,258
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   29,366      44,066         88,098     102,196
    Cumulative Preferred Stock . . . . .    1,183       1,186          3,550       3,573
  Capital Stock Expense. . . . . . . . .       25          33             77         971

BALANCE AT END OF PERIOD . . . . . . . . $288,060    $285,589       $288,060    $285,589

The common stock of the Company is wholly owned 
by American Electric Power Company, Inc.
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1998            1997    
                                                                 (in thousands)
ASSETS
<S>                                                        <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,555,893      $2,545,484
  Transmission . . . . . . . . . . . . . . . . . . . .        912,155         908,736
  Distribution . . . . . . . . . . . . . . . . . . . .        756,348         737,902
  General (including nuclear fuel) . . . . . . . . . .        229,589         233,888
  Construction Work in Progress. . . . . . . . . . . .        129,122          88,487
          Total Electric Utility Plant . . . . . . . .      4,583,107       4,514,497
  Accumulated Depreciation and Amortization. . . . . .      2,049,510       1,973,937

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,533,597       2,540,560

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
 DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . . . .        627,792         566,390

OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        211,848         156,085



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         10,838           5,860
  Accounts Receivable. . . . . . . . . . . . . . . . .        171,428         137,310
  Allowance For Uncollectible Accounts . . . . . . . .         (1,978)         (1,188)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         15,985          17,182
  Materials and Supplies . . . . . . . . . . . . . . .         80,206          78,701
  Accrued Utility Revenues . . . . . . . . . . . . . .         40,378          30,521
  Prepayments. . . . . . . . . . . . . . . . . . . . .          7,821           4,828

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        324,678         273,214




REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        413,799         400,489

DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         30,583          31,060



            TOTAL. . . . . . . . . . . . . . . . . . .     $4,142,297      $3,967,798
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                         September 30,    December 31,
                                                              1998            1997    
                                                                 (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. . . . . . . . . . . . . . . . . . .       732,573          732,472
  Retained Earnings. . . . . . . . . . . . . . . . . .       288,060          278,814
          Total Common Shareholder's Equity. . . . . .     1,077,217        1,067,870
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .         9,346            9,435
    Subject to Mandatory Redemption. . . . . . . . . .        68,445           68,445
  Long-term Debt . . . . . . . . . . . . . . . . . . .     1,124,961        1,014,237

          TOTAL CAPITALIZATION . . . . . . . . . . . .     2,279,969        2,159,987

OTHER NONCURRENT LIABILITIES:
  Nuclear Decommissioning. . . . . . . . . . . . . . .       440,447          381,016
  Other. . . . . . . . . . . . . . . . . . . . . . . .       236,876          232,667

          TOTAL OTHER NONCURRENT LIABILITIES . . . . .       677,323          613,683

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .          -              35,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .       103,500          119,600
  Accounts Payable . . . . . . . . . . . . . . . . . .        79,011           68,394
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .        43,615           46,850
  Interest Accrued . . . . . . . . . . . . . . . . . .        16,081           15,741
  Rent Accrued - Rockport Plant Unit 2 . . . . . . . .        23,427            4,963
  Obligations Under Capital Leases . . . . . . . . . .        32,976           34,033
  Other. . . . . . . . . . . . . . . . . . . . . . . .        79,289           58,548

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       377,899          383,129

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       559,596          559,708

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       132,318          138,045

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .        89,639           92,419

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        25,553           20,827

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .    $4,142,297       $3,967,798
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                 Nine Months Ended
                                                                    September 30,     
                                                                 1998           1997
                                                                   (in thousands)
<S>                                                           <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 100,971      $ 123,258
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    111,510        111,176
    Amortization of Rockport Plant Unit 1 
      Phase-in Plan Deferrals. . . . . . . . . . . . . . . .       -            10,821
    Deferral of Incremental Nuclear Refueling
      Outage Expenses (net). . . . . . . . . . . . . . . . .     11,368         (2,402)
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     11,226         (9,753)
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (5,727)        (5,906)
    Under-recovery of Fuel and Purchased Power . . . . . . .    (42,676)        (9,554)
   Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (33,328)         7,029
    Fuel, Materials and Supplies . . . . . . . . . . . . . .       (308)         8,705
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     (9,857)         7,284
    Accounts Payable . . . . . . . . . . . . . . . . . . . .     10,617        (36,462)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .     (3,235)       (13,615)
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .     18,464         18,464
  Payment of Disputed Tax and Interest Related to COLI . . .    (53,628)          -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     24,237         26,966
        Net Cash Flows From Operating Activities . . . . . .    139,634        236,011

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .    (98,218)       (79,066)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .      4,154          1,798
        Net Cash Flows Used For Investing Activities . . . .    (94,064)       (77,268)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    122,222         47,728
  Retirement of Cumulative Preferred Stock . . . . . . . . .        (65)       (78,838)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (55,000)       (50,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (16,100)        14,350
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (88,098)       (87,195)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (3,551)        (4,746)
        Net Cash Flows Used For Financing Activities . . . .    (40,592)      (158,701)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .      4,978             42
Cash and Cash Equivalents at Beginning of Period . . . . . .      5,860          8,233
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  10,838      $   8,275

Supplemental Disclosure:
  Cash paid  for interest  net of capitalized amounts was  $49,041,000 and $44,575,000 
  and for income taxes was $20,224,000 and $83,580,000 in 1998 and 1997, respectively.
  Noncash acquisitions under  capital leases  were $7,050,000 and  $80,231,000 in 1998 
  and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
         INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        SEPTEMBER 30, 1998              
                           (UNAUDITED)

1.  GENERAL

         The accompanying unaudited consolidated financial
     statements should be read in conjunction with the 1997 Annual
     Report as incorporated in and filed with the Form 10-K.  In the
     opinion of management, the financial statements reflect all
     adjustments (consisting of only normal recurring accruals)
     which are necessary for a fair presentation of the results of
     operations and financial condition for interim periods.

2.   FINANCING ACTIVITIES

         In 1998 the Company redeemed $35 million of 7.00% first
     mortgage bonds at maturity and $20 million of 7.80% first
     mortgage bonds due 2023 at face value.  In May 1998 $125
     million of 7.60% junior subordinated deferrable interest
     debentures due 2038 were issued.

3.   NEW ACCOUNTING STANDARDS

         Statement of Financial Accounting Standards (SFAS) No. 130
     "Reporting Comprehensive Income" was adopted by the Company in
     the first quarter of 1998.  SFAS No. 130 established the
     standards for reporting and displaying components of
     "comprehensive income," which is the total of net income and
     all transactions not included in net income affecting equity
     except those with shareholders.  For the quarter and year-to-date periods
     ended September 30, 1998, there are no material
     differences between comprehensive income and net income.

         In the first quarter of 1998 the Company adopted the
     American Institute of Certified Public Accountants' Statement
     of Position (SOP) 98-1, "Accounting for the Costs of Computer
     Software Developed or Obtained for Internal Use." The SOP
     requires the capitalization and amortization of certain costs
     of acquiring or developing internal use computer software. 
     Previously the Company expensed all software acquisition and
     development costs.  The SOP must be adopted at the beginning
     of a fiscal year with no restatement or retroactive adjustment
     of prior periods.  The adoption of the SOP effective January
     1, 1998 did not have a material effect on results of
     operations, cash flows or financial condition.

4.   POWER MARKETING AND TRADING

         During 1998, American Electric Power Service Corporation,
     as agent for the Company and its affiliates in the AEP System
     Power Pool (Power Pool), substantially increased the volume of
     its electricity marketing and trading.  The purpose of the
     power marketing and trading business is to utilize AEP's 

<PAGE>
     knowledge of the energy markets in order to improve the
     competitiveness of its generation business and contribute to
     net income.  Revenues and expenses from these activities are
     shared by the Power Pool members based on their relative peak
     demands.

         The power marketing and trading business involves the
     marketing of power under physical forward contracts at fixed
     and variable prices and the trading of options, futures, swaps
     and other financial derivative contracts at both fixed and
     variable prices.  Most contracts represent physical forward
     electricity marketing contracts for the purchase and sale of
     electricity in the Power Pool's traditional marketing area
     which are recorded as operating revenues and purchased power
     expense  when the contracts settle.  At September 30, 1998, the
     Power Pool had open marketing contracts, not on the balance
     sheet, in its traditional marketing area through the year 2004
     to sell electricity with a notional value of approximately $1.1
     billion and to purchase electricity with a notional value of
     approximately $1.1 billion.  The Company's share of these
     notional values is approximately $200 million.

         The Power Pool has also purchased and sold electricity
     options, futures, and swaps, and entered into forward purchase
     and sale contracts for the future delivery or receipt of
     electricity outside its traditional marketing area.  These
     transactions represent non-regulated trading activities that
     are marked-to-market and recorded in nonoperating income.  At
     September 30, 1998 the Company's share of the unrealized mark-to-market
     gains and losses of such trading contracts are
     reported as assets and liabilities, respectively.  At September
     30, 1998, the Power Pool had open marketing contracts outside
     its traditional marketing area through the year 2008 to sell
     electricity with a notional value of approximately $230 million
     and to purchase electricity with a notional value of
     approximately $145 million.  The Company's share of these
     notional values is approximately $45 million for sales and
     approximately $30 million for purchases.

         Dependent on future electricity market conditions these
     activities could produce material income or losses in future
     periods.

5.   CONTINGENCIES

     Taxes

         As discussed in Note 7, "Federal Income Taxes" of the Notes
     to Consolidated Financial Statements in the 1997 Annual Report,
     the Internal Revenue Service (IRS) agents auditing the AEP
     System's consolidated federal income tax returns requested a
     ruling from their National Office that certain interest
     deductions relating to corporate owned life insurance (COLI)
     claimed by the Company should not be allowed.  As a result of
     a suit filed in United States District Court (discussed below) 

<PAGE>
     this request for ruling has been withdrawn.  Adjustments have
     been or will be proposed by the IRS disallowing COLI interest
     deductions for taxable years 1991-96.  A disallowance of the
     COLI interest deduction through September 30, 1998 would reduce
     earnings by approximately $64 million (including interest). 
     The Company has made no provision for any possible adverse
     earnings impact from this matter.

         In order to resolve this issue without further delay, on
     March 24, 1998, the Company filed suit against the United
     States in the United States District Court for the Southern
     District of Ohio.  Management believes that it has a
     meritorious position and will vigorously pursue this lawsuit. 
     In July 1998, the Company made a payment of taxes and interest
     attributable to COLI interest deductions for taxable years
     1991-96 to avoid the potential assessment by the IRS of any
     additional above market rate interest on the contested amount. 
     In September 1998 the Company made an additional payment for
     the 1997 tax year.  The payments were included on the balance
     sheet in other property and investments pending the resolution
     of this matter.  The Company will seek refund, either
     administratively or through litigation, of all amounts paid. 
     In the event the resolution of this matter is unfavorable, it
     will have a material adverse impact on results of operations
     and cash flows.

     Cook Nuclear Plant Shutdown

         As discussed in Note 3 of the Notes to Consolidated
     Financial Statements in the 1997 Annual Report, both units of
     the Cook Nuclear Plant were shut down by the Company in
     September 1997 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 the issues identified in the letter. 
     The Company is working with the NRC to resolve a remaining
     issue in the letter.

         On April 17, 1998, the NRC notified the Company that it had
     convened a Restart Panel for the Cook Plant.  On July 30, 1998,
     the Company received a letter from the NRC providing the NRC's
     list of required restart activities.  The Company is and will
     be meeting with the Panel on a regular basis, until the Cook
     Plant units are returned to service, to identify and address
     the issues necessary for the restart of the units.  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.
<PAGE>
<PAGE>
         The current restart schedule indicates Unit 1 is expected
     to return to service by the end of the first quarter of 1999. 
     The restart schedule for Unit 2 has not been completed;
     however, management anticipates that Unit 2 may return to
     service 90 days after Unit 1.  If the units are not returned
     to service, there could be a material adverse effect on
     financial condition.

         The incremental cost expected to be incurred to restart the
     Cook units is approximately $70 million for 1998, of which $34
     million has been incurred through September 30, 1998.  However,
     approximately $20 million of previously budgeted work for 1998
     at the Cook Plant will not be incurred and will partially
     mitigate the incremental restart costs.  The cost and schedule
     for the outage during 1999 could be significantly impacted if
     additional work is identified beyond the $35 million planned
     for the first quarter.

         On July 24, 1998, the Company received an "adverse trend
     letter" from the NRC indicating that NRC senior managers had
     determined that there had been a slow decline in performance
     at the Cook Plant during the 18 month period preceding the
     letter.  The letter indicated that the NRC will closely monitor
     efforts to address issues at Cook Plant through additional
     inspection activities.

         In a letter dated October 13, 1998, the NRC issued to the
     Company a Notice of Violation and proposed $500,000 civil
     penalty for alleged violations at the Cook Plant discovered
     during five inspections conducted between August 4, 1997 and
     April 15, 1998.   The Company paid the penalty.

         The cost of electricity supplied to retail customers rose
     due to the outage of the two units since higher cost coal-fired
     generation and purchased power were substituted for low cost
     nuclear generation.  In the Indiana and Michigan retail
     jurisdictions fuel cost recovery mechanisms permit the
     recovery, subject to regulatory commission review and approval,
     of changes in fuel costs including the fuel component of
     purchased power in the Indiana jurisdiction and changes in
     replacement power in the Michigan jurisdiction.  Under the fuel
     cost recovery mechanisms, retail rates contain a fuel cost
     adjustment factor that reflects estimated fuel costs for the
     period during which the factor will be in effect subject to
     reconciliation to actual fuel costs in a future proceeding. 
     When actual fuel costs exceed the estimated costs reflected in
     the billing factor as was the case with regard to Cook, a
     regulatory asset is recorded and revenues are accrued.

<PAGE>
<PAGE>
         Due to the unscheduled Cook Plant outage, the Company's
     actual fuel costs significantly exceeded the estimated fuel
     costs reflected in its fuel cost adjustment factors.  A
     regulatory asset has been recorded for revenues accrued in
     anticipation of future reconciliation and billing of the higher
     fuel costs to customers.  At September 30, 1998, the regulatory
     asset was $61 million.

         The Indiana Utility Regulatory Commission approved two
     agreements authorizing the Company during the billing months
     of July through December 1998 to apply a fuel cost adjustment
     factor less than that requested by the Company, subject to
     future reconciliation or refund.  The agreements provide the
     parties to the proceedings with the opportunity to conduct
     discovery regarding certain issues that were raised in the
     proceedings, including the recovery of replacement energy cost
     due to the extended Cook Plant outage, in anticipation of
     resolving the issues in a future fuel cost adjustment
     proceeding.  Management believes that the Company should be
     able to recover the Cook replacement energy costs; however, if
     recovery of the replacement costs is denied, results of
     operations and cash flows would be adversely affected.

     Revised Air Quality Standards 
     
         The United States Environmental Protection Agency (Federal
     EPA) published in October 1997 a proposed nitrogen oxides (NOx)
     emissions reduction rule which called for new state
     implementation plans (SIPs).  SIPs are a procedural method used
     by each state to comply with Federal EPA rules.  Eight
     northeastern states also filed petitions in 1997 with Federal
     EPA claiming NOx emissions from plants in midwestern states
     prevent them from complying with air quality standards.

         On September 24, 1998, Federal EPA issued final rules which
     require reductions in NOx emissions in 22 eastern states,
     including the states in which the Company's generating plants
     are located.  The implementation of the final rules would be
     achieved through the revision of SIPs by September 1999 that,
     by the year 2003, anticipate the imposition of a NOx reduction
     on utility sources of approximately 85% below 1990 emission
     levels.  On October 30, 1998, a number of utilities, including
     the Company and its affiliates in the AEP System, filed a
     petition in the U.S. Court of Appeals for the District of
     Columbia Circuit seeking a review of the final rules.

         Should the states fail to adopt the required revisions to
     their SIPs within one year of the date of the final rules
     (September 24, 1999), Federal EPA has proposed to implement a
     federal plan to accomplish the NOx reductions.  Federal EPA
     also proposed the approval of portions of the petitions filed
     by the eight northeastern states that would result in
     imposition of NOx emission reductions on utility and industrial
     sources.  These reductions are substantially the same as those
     required by the final rules and could be adopted by Federal EPA 

<PAGE>
     in the event the states fail to implement SIPs in accordance
     with the final rules.

         Based on initial studies, preliminary estimates indicate
     that compliance costs could result in capital expenditures of
     approximately $169 million.  Compliance costs can not be
     estimated with certainty and the actual costs incurred to
     comply could be significantly different from the preliminary
     estimate depending upon the compliance alternatives selected
     to achieve reductions in NOx emissions.  Unless such costs are
     recovered from customers, they would have a material adverse
     effect on results of operations, cash flows and possibly
     financial condition

     Other

         The Company continues to be involved in certain other
          matters discussed in its 1997 Annual Report.<PAGE>
<PAGE>
         INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                     AND FINANCIAL CONDITION                   
            THIRD QUARTER 1998 vs. THIRD QUARTER 1997
                               AND
             YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
RESULTS OF OPERATIONS
     Despite substantial increases in operating revenues due to 
increased retail sales and power marketing and trading activities,
net income decreased $6.4 million or 14% for the quarter and $22.3
million or 18% for the year-to-date period.  The decreases in net
income are due primarily to increased costs related to an extended
Cook Nuclear Plant outage, increased purchased power costs, losses
on certain energy trades outside AEP's traditional market area and
a decrease in capacity credits from the AEP System Power Pool
(Power Pool).  Under the terms of the Power Pool, capacity credits
and charges are designed to allocate the cost of the AEP System's
capacity among the Power Pool members based on their relative peak
demands and generating reserves.  The reduction in capacity credits
received can be attributed to an increase in the Company's prior
twelve month peak demand relative to the total peak demand of all
Power Pool members.
     As discussed in Note 5 of the Notes to Consolidated Financial
Statements, the Cook Nuclear Plant was shut down in September 1997. 
The shutdown has had a significant impact on the operations of the
Company as reflected in the variations of certain income statement
line items discussed below.
     Income statement line items which changed significantly were:
                                    Increase (Decrease)          
                             Third Quarter         Year-to-Date  
                          (in millions)   %     (in millions)  % 

Operating Revenues . . . .   $583.4     161       $  955.0    93
Fuel Expense . . . . . . .    (11.3)    (18)         (42.3)  (24)
Purchased Power Expense. .    571.3     N.M.       1,002.4   N.M.
Other Operation Expense. .     17.6      22           17.0     7
Maintenance Expense. . . .      9.7      33           14.3    17
Amortization of Rockport
 Plant Unit 1 Phase-in
 Plan Deferrals. . . . . .     (3.0)    N.M.         (10.8)  N.M.
Federal Income Taxes . . .     (0.9)     (4)          (9.7)  (16)
Nonoperating Income. . . .     (2.9)    N.M.          (1.3)  (87)
N.M. = Not Meaningful<PAGE>
<PAGE>
     Operating revenues increased significantly in both periods due
predominantly to an increase in sales to retail and wholesale
customers.  The increase in retail revenues can be attributed to
increased energy sales to all retail customer classes reflecting
warmer summer weather and increased industrial customer usage. 
Fuel and power supply cost recovery accruals also contributed to
the increase in retail revenues.  Under the fuel cost recovery
mechanism, revenues are accrued to match increased fuel expense in
both of the Company's retail jurisdictions and for replacement
power costs in the Michigan jurisdiction.  The fuel and purchased
power costs incurred are subsequently reviewed by the commissions
and, if acceptable, approved for recovery through billings.  During
the extended outage of both nuclear units, retail revenues
increased from the accrual of revenues to match the increased fuel
costs and purchase power expense incurred to replace the
unavailable lower cost nuclear power.
     Revenues from wholesale customers increased reflecting growth
in power marketing and trading activities.
     Fuel expense decreased significantly in both periods due to a
decline in nuclear generation reflecting the outages of both
nuclear units in 1998.
     The significant increase in purchased power expense for both
periods was the result of purchases for the power marketing and
trading business and additional energy purchases from the Power
Pool due to the unavailability of the nuclear units.
     Other operation expense increased for both periods as a result
of costs associated with the extended Cook Plant outage and
increased incentive pay accruals.
     The increase in maintenance expense for both periods was the
result of additional expenditures to prepare the nuclear units for
restart.
     The recovery periods for Rockport Plant Unit 1 costs deferred
under a rate phase-in plan in the Indiana and FERC jurisdictions
ended in the fall of 1997 causing the decrease in amortization of
phase-in plan deferrals.  The deferred costs were amortized over a
10-year period commensurate with their collection from customers
pursuant to commission orders.  The Company has increased its 

<PAGE>
decommissioning expense accruals (approximately $12 million through
September 30, 1998), pending approval from the Indiana Utility
Regulatory Commission (IURC), in an amount equal to the continuing
phase-in plan revenues.  On November 12, 1998 the IURC issued an
order that denied the Company's request to increase its
decommissioning accruals and requires the Company to submit revised
quarterly net operating income calculations for each quarter
subsequent to August 1997.  The Company will be making the revised
calculations and under the worst case scenario there would be no
favorable impact on results of operations.
     Federal income taxes attributable to operations decreased for
the year-to-date period as a result of a decrease in pre-tax
operating income.
     The decrease in nonoperating income is primarily due to losses
on certain power marketing and trading transactions.  These
transactions, which are marked-to-market and described in footnote
4, represent non-regulated trading activities outside the Company's
traditional marketing area.  Although losses were incurred on these
non-regulated energy trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.
FINANCIAL CONDITION
     Total plant and property additions including capital leases for
the year-to-date period were $106 million.  During the first nine
months of 1998 short-term debt outstanding decreased by $16
million.
     During the first nine months of 1998 the Company redeemed two
series of first mortgage bonds; $35 million at 7.00% at maturity
and $20 million at 7.80% due 2023, and issued $125 million of 7.60%
junior subordinated deferrable interest debentures due 2038.
COOK NUCLEAR PLANT SHUTDOWN
     As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1997 Annual Report, both units of the Cook
Nuclear Plant were shut down by the Company in September 1997 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 
<PAGE>
Letter in September 1997 requiring the Company to address the
issues identified in the letter.  The Company is working with the
NRC to resolve a remaining issue in the letter.
     On April 17, 1998, the NRC notified the Company that it had
convened a Restart Panel for the Cook Plant.  On July 30, 1998, the
Company received a letter from the NRC providing the NRC's list of
required restart activities.  The Company is and will be meeting
with the Panel on a regular basis, until the Cook Plant units are
returned to service, to identify and address the issues necessary
for the restart of the units.  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.
     The current restart schedule indicates Unit 1 is expected to
return to service by the end of the first quarter of 1999.  The
restart schedule for Unit 2 has not been completed; however,
management anticipates that Unit 2 may return to service 90 days
after Unit 1.  If the units are not returned to service, there
could be a material adverse effect on financial condition.
     The incremental cost expected to be incurred to restart the
Cook units is approximately $70 million for 1998, of which $34
million has been incurred through September 30, 1998.  However,
approximately $20 million of previously budgeted work for 1998 at
the Cook Plant will not be incurred and will partially mitigate the
incremental restart costs.  The cost and schedule for the outage
during 1999 could be significantly impacted if additional work is
identified beyond the $35 million planned for the first quarter.
     On July 24, 1998, the Company received an "adverse trend
letter" from the NRC indicating that NRC senior managers had
determined that there had been a slow decline in performance at the
Cook Plant during the 18 month period preceding the letter.  The
letter indicated that the NRC will closely monitor efforts to
address issues at Cook Plant through additional inspection
activities.
<PAGE>
<PAGE>
     In a letter dated October 13, 1998, the NRC issued to the
Company a Notice of Violation and proposed $500,000 civil penalty
for alleged violations at the Cook Plant discovered during five
inspections conducted between August 4, 1997 and April 15, 1998. 
The Company paid the penalty.
     As a result of the extended outage, the cost of electricity
supplied to retail customers increased since higher cost coal-fired
generation and purchased power were substituted for low cost
nuclear generation.  In the Indiana and Michigan retail
jurisdictions fuel cost recovery mechanisms permit the recovery,
subject to regulatory commission review and approval, of changes in
fuel costs including the fuel component of purchased power in the
Indiana jurisdiction and changes in replacement power in the
Michigan jurisdiction.  Under the fuel cost recovery mechanisms,
retail rates contain a fuel cost adjustment factor that reflects
estimated fuel costs for the period during which the factor will be
in effect subject to reconciliation to actual fuel costs in a
future proceeding.  When actual fuel costs exceed the estimated
costs reflected in the billing factor, a regulatory asset is
recorded and revenues are accrued.
     Due to the unscheduled Cook Plant outage, the Company's actual
fuel costs significantly exceeded the estimated fuel costs
reflected in its fuel cost adjustment factors.  A regulatory asset
has been recorded for revenues accrued in anticipation of future
reconciliation and billing of the higher fuel costs to customers. 
At September 30, 1998, the regulatory asset was $61 million.
     The IURC approved two agreements authorizing the Company during
the billing months of July through December 1998 to apply a fuel
cost adjustment factor less than that requested by the Company,
subject to future reconciliation or refund.  The agreements provide
the parties to the proceedings with the opportunity to conduct
discovery regarding certain issues that were raised in the
proceedings, including the recovery of replacement energy cost due
to the Cook Plant outage, in anticipation of resolving the issues
in a future fuel cost adjustment proceeding.  Management believes
that the Company should be able to recover the Cook replacement
costs; however, if recovery of the replacement costs is denied, <PAGE>
<PAGE>
results of operations and cash flows would be adversely affected.
     The timetable for the return to service of the Cook Plant
constitute "forward looking statements" as defined in the Private
Securities Litigation Reform Act of 1995.  Such statements and
estimates could differ materially from actual results because of
factors referred to specifically in connection with such forward-looking 
statements and, in addition, other unforeseen issues
encountered in preparing the Cook Plant for restart and the
unpredictability of the NRC regulatory process.
REVISED AIR QUALITY STANDARDS
     The United States Environmental Protection Agency (Federal EPA)
published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state implementation
plans (SIPs).  SIPs are a procedural method used by each state to
comply with Federal EPA rules.  Eight northeastern states also
filed petitions in 1997 with Federal EPA claiming NOx emissions
from plants in midwestern states prevent them from complying with
air quality standards.
     On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states, including
the states in which the Company's generating plants are located. 
The implementation of the final rules would be achieved through the
revision of SIPs by September 1999 that, by the year 2003,
anticipate the imposition of a NOx reduction on utility sources of
approximately 85% below 1990 emission levels.  On October 30, 1998,
a number of utilities, including the Company and its affiliates in
the AEP System, filed a petition in the U.S. Court of Appeals for
the District of Columbia Circuit seeking a review of the final
rules.
     Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions.  Federal EPA also proposed the
approval of portions of the petitions filed by the eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources.  These reductions are
substantially the same as those required by the final rules and <PAGE>
<PAGE>
could be adopted by Federal EPA in the event the states fail to
implement SIPs in accordance with the final rules.
     Based on initial studies, preliminary estimates indicate that
compliance costs could result in capital expenditures of
approximately $169 million.  Compliance costs can not be estimated
with certainty and the actual costs incurred to comply could be
significantly different from the preliminary estimate depending
upon the compliance alternatives selected to achieve reductions in
NOx emissions.  Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations,
cash flows and possibly financial condition.
POWER MARKETING AND TRADING
     During 1998, American Electric Power Service Corporation, as
agent for the Company and its affiliates in the Power Pool,
substantially increased the volume of its electricity marketing and
trading.  The purpose of the power marketing and trading business
is to utilize AEP's knowledge of the energy markets in order to
improve the competitiveness of its generation business and
contribute to net income.  Revenues and expenses from these
activities are shared by the Power Pool members based on their
relative peak demands.
     The power marketing and trading business involves the marketing
of power under physical forward contracts at fixed and variable
prices and the trading of options, futures, swaps and other
financial derivative contracts at both fixed and variable prices. 
Most contracts represent physical forward electricity marketing
contracts for the purchase and sale of electricity in the Power
Pool's traditional marketing area which are recorded as operating
revenues and purchased power expense  when the contracts settle. 
At September 30, 1998, the Power Pool had open marketing contracts,
not on the balance sheet, in its traditional marketing area through
the year 2004 to sell electricity with a notional value of
approximately $1.1 billion and to purchase electricity with a
notional value of approximately $1.1 billion.  The Company's share
of these notional values is approximately $200 million.
<PAGE>
<PAGE>
     The Power Pool has also purchased and sold electricity options,
futures, and swaps, and entered into forward purchase and sale
contracts for the future delivery or receipt of electricity outside
its traditional marketing area.  These transactions represent non-regulated
trading activities that are marked-to-market and recorded
in nonoperating income.  At September 30, 1998 the Company's share
of the unrealized mark-to-market gains and losses of such trading
contracts are reported as assets and liabilities, respectively.  At
September 30, 1998, the Power Pool had open marketing contracts
outside its traditional marketing area through the year 2008 to
sell electricity with a notional value of approximately $230
million and to purchase electricity with a notional value of
approximately $145 million.  The Company's share of these notional
values is approximately $45 million for sales and approximately $30
million for purchases.
     Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
TAXES
     As discussed in Note 7, "Federal Income Taxes" of the Notes to
Consolidated Financial Statements in the 1997 Annual Report, the
Internal Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from
their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company should
not be allowed.  As a result of a suit filed in United States
District Court (discussed below) this request for ruling has been
withdrawn.  Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions for taxable years 1991-96.  A
disallowance of the COLI interest deduction through September 30,
1998 would reduce earnings by approximately $64 million (including
interest).  The Company has made no provision for any possible
adverse earnings impact from this matter.
<PAGE>
<PAGE>
     In order to resolve this issue without further delay, on March
24, 1998, the Company filed suit against the United States in the
United States District Court for the Southern District of Ohio. 
Management believes that it has a meritorious position and will
vigorously pursue this lawsuit.  In July 1998, the Company made a
payment of taxes and interest attributable to COLI interest
deductions for taxable years 1991-96 to avoid the potential
assessment by the IRS of any additional above market rate interest
on the contested amount.  In September 1998 the Company made an
additional payment for the 1997 tax year.  The payments were
included on the balance sheet in other property and investments
pending the resolution of this matter.  The Company will seek
refund,  either  administratively  or  through  litigation, of  all 
amounts paid.  In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations and cash flows.
COMPUTER ISSUE - YEAR 2000
     On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems were 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-Year
2000 ready programs.

     Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Year 2000-related failures and repair such failures if they occur. 
This includes both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), 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 <PAGE>
<PAGE>
the external evaluation, the Company has sought written assurances
from third parties regarding their state of Year 2000 readiness.
     Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system. 
AEP, along with other electric utilities in North America,
regularly submits information to the North American Electric
Reliability Council (NERC) as part of NERC's Year 2000 readiness
program.  NERC then publicly reports summary information to the
U.S. Department of Energy regarding the Year 2000 readiness of
electric utilities.  In 1999 AEP plans to participate in two
NERC-sponsored coordinated electric industry Year 2000 readiness
drills.  The first NERC report, dated September 17, 1998 and titled
Preparing the Electric Power Systems of North America for
Transition to the Year 2000-A Status Report and Work Plan, states
that: "Mission critical systems and components are to be made Y2K
Ready by June 30, 1999."  In addition, the report indicates that:
"While many organizations are on track to meet these targets, many
others need to accelerate project plans and resources."  In
response to the report, the Company has accelerated its Year 2000
readiness date for mission critical and high priority systems and
components from September 30, 1999 to June 30, 1999.
     Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems.  Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.
     Various state regulatory commissions are also reviewing the
Year 2000 readiness of electric utilities subject to their
jurisdiction.

     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,
communications, and the physical generation and delivery of energy;
followed by back office activities such as customer
service/billing, regulatory reporting, internal reporting and
administrative activities (e.g. payroll, procurement, accounts <PAGE>
<PAGE>
payable); and finally, those activities that would cause
inconvenience or productivity loss in normal business operations.
     The following chart shows our progress toward becoming ready
for the Year 2000 as of September 30, 1998:
                             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%         11/30/1998    86%
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     2%
replacing or retiring                     60%
those mission critical and                        
high priority digital-based
systems with problems                     Client
processing dates past the                 Server:
Year 2000. Testing these                  1%
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
September 30, 1998, the Company has spent $3 million on the Year
2000 project and, estimates spending an additional $7 million to
$10 million to achieve Year 2000 readiness.  Most Year 2000 costs
are software, IT consultant and salary-related 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 Year 2000 ready is not expected to have a material impact
on the Company's results of operations, cash flows or financial <PAGE>
<PAGE>
condition.
     Risks of the Company's Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Year 2000 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.

     In addition, although as discussed 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, Year 2000-related issues may materially adversely
affect AEP.

     Company's Contingency Plans - The Company intends to establish
contingency plans on a case-by-case basis to address alternatives
if Year 2000 failures of automatic systems and equipment occur as
part of its Year 2000 readiness program.  The contingency plans
will be based upon a risk analysis process and will be developed by
the fourth quarter of 1999.  These plans will build upon disaster <PAGE>
<PAGE>
recovery, system restoration, and contingency planning that we now
have in place.  We have begun the contingency planning process,
including the review of NERC's Contingency Planning Guide.  The
Company plans to submit a draft of its contingency plans to NERC as
part of NERC's review of drafts of regional and individual electric
utility contingency plans in 1999.

     Forward-Looking Statements - This description of Year 2000
problems, the consequences of Year 2000 failures and the estimated
costs of, and timetable for, becoming Year 2000 ready constitute
"forward looking statements" as defined in the Private Securities
Litigation Reform Act of 1995.  Such statements are based on
management's beliefs as well as assumptions made by, and
information currently available to, management.  Investors are
cautioned that such statements and estimates could differ
materially from actual results because of factors referred to
specifically in connection with such forward-looking statements
and, in addition, the following other factors, among others:
     *   Continuing availability of experienced consultants and IT
         personnel and related resources
     *   Ability of third parties to complete their Year 2000
         remediations on a timely basis and accuracy of
         representations made by such third parties concerning
         their Year 2000 readiness
     *   Ability of the Company to identify and implement
         contingency plans.
<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                           STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                           Three Months Ended        Nine Months Ended
                                              September 30,            September 30,    
                                             1998        1997        1998         1997
                                                          (in thousands)
<S>                                        <C>         <C>         <C>          <C>
OPERATING REVENUES . . . . . . . . . . . . $282,319    $89,791     $571,743     $256,472

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . .   21,478     20,020       61,963       58,647
  Purchased Power. . . . . . . . . . . . .  208,945     28,632      375,333       73,775
  Other Operation. . . . . . . . . . . . .   13,647     13,241       36,633       37,130
  Maintenance. . . . . . . . . . . . . . .    7,335      6,148       23,759       16,826
  Depreciation and Amortization. . . . . .    7,068      6,649       20,956       19,708
  Taxes Other Than Federal Income Taxes. .    2,668      2,427        7,420        7,266
  Federal Income Taxes . . . . . . . . . .    4,627      1,837        7,406        7,614

         TOTAL OPERATING EXPENSES. . . . .  265,768     78,954      533,470      220,966

OPERATING INCOME . . . . . . . . . . . . .   16,551     10,837       38,273       35,506

NONOPERATING LOSS. . . . . . . . . . . . .     (902)       (62)      (1,066)        (351)

INCOME BEFORE INTEREST CHARGES . . . . . .   15,649     10,775       37,207       35,155

INTEREST CHARGES . . . . . . . . . . . . .    7,207      6,323       21,335       18,431

NET INCOME . . . . . . . . . . . . . . . . $  8,442    $ 4,452     $ 15,872     $ 16,724


                                                                               

                      STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended        Nine Months Ended
                                              September 30,            September 30,    
                                             1998        1997        1998         1997
                                                          (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . $71,356     $82,982      $78,076      $84,090

NET INCOME . . . . . . . . . . . . . . . .   8,442       4,452       15,872       16,724

CASH DIVIDENDS DECLARED. . . . . . . . . .   7,075       6,690       21,225       20,070

BALANCE AT END OF PERIOD . . . . . . . . . $72,723     $80,744      $72,723      $80,744

                    

The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
</TABLE>
See Notes to Financial Statements.<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                         September 30,    December 31,
                                                             1998             1997    
                                                                (in thousands)
ASSETS
<S>                                                        <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $  259,980      $  249,184
  Transmission . . . . . . . . . . . . . . . . . . . .        325,854         303,456
  Distribution . . . . . . . . . . . . . . . . . . . .        347,834         350,793
  General. . . . . . . . . . . . . . . . . . . . . . .         74,670          71,462
  Construction Work in Progress. . . . . . . . . . . .         24,167          32,060
          Total Electric Utility Plant . . . . . . . .      1,032,505       1,006,955
  Accumulated Depreciation and Amortization. . . . . .        310,083         296,318

          NET ELECTRIC UTILITY PLANT . . . . . . . . .        722,422         710,637

OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         12,031           6,414

CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .            955           1,381
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         18,122          24,127
    Affiliated Companies . . . . . . . . . . . . . . .         11,469           1,722
    Miscellaneous. . . . . . . . . . . . . . . . . . .          4,221           3,276
    Allowance for Uncollectible Accounts . . . . . . .           (698)           (525)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .          9,300          10,685
  Materials and Supplies . . . . . . . . . . . . . . .         14,212          14,054
  Accrued Utility Revenues . . . . . . . . . . . . . .         11,587          12,981
  Other. . . . . . . . . . . . . . . . . . . . . . . .          3,568           1,715

          TOTAL CURRENT ASSETS . . . . . . . . . . . .         72,736          69,416


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         91,502          90,045

DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .          6,788          10,159

            TOTAL. . . . . . . . . . . . . . . . . . .     $  905,479      $  886,671
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1998            1997    
                                                                 (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. . . . . . . . . . . . . . . . . . .       138,750         128,750
  Retained Earnings. . . . . . . . . . . . . . . . . .        72,723          78,076
          Total Common Shareholder's Equity. . . . . .       261,923         257,276
  Long-term Debt . . . . . . . . . . . . . . . . . . .       313,979         341,051

          TOTAL CAPITALIZATION . . . . . . . . . . . .       575,902         598,327

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        28,124          26,544

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .        25,000            -
  Short-term Debt. . . . . . . . . . . . . . . . . . .        49,350          36,500
  Accounts Payable . . . . . . . . . . . . . . . . . .        20,817          24,574
  Customer Deposits. . . . . . . . . . . . . . . . . .         3,999           3,660
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         4,937           6,130
  Interest Accrued . . . . . . . . . . . . . . . . . .         8,097           6,015
  Other. . . . . . . . . . . . . . . . . . . . . . . .        18,069          15,084

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       130,269          91,963

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       155,655         153,945

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        14,700          15,615

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .           829             277

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .      $905,479        $886,671
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                         STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                Nine Months Ended
                                                                  September 30,     
                                                                1998          1997
                                                                  (in thousands)
<S>                                                           <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 15,872      $ 16,724
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    20,966        19,718
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     1,173           163
    Deferred Investment Tax Credits. . . . . . . . . . . . .      (915)         (924)
    Amortization of Deferred Property Taxes. . . . . . . . .     3,840         3,690
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (4,514)         (305)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     1,227          (113)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     1,394         1,712
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (3,757)       (9,040)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (1,193)       (1,237)
  Payment of Disputed Taxes and Interest Related to COLI . .    (5,376)         -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     1,952         5,301
        Net Cash Flows From Operating Activities . . . . . .    30,669        35,689

INVESTING ACTIVITIES - Construction Expenditures . . . . . .   (30,517)      (45,023)

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .    10,000        10,000
  Change in Short-term Debt (net). . . . . . . . . . . . . .    12,850        19,775 
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (2,203)         -
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .   (21,225)      (20,070)
        Net Cash Flows From (Used For) Financing Activities.      (578)        9,705

Net Increase (Decrease) in Cash and Cash Equivalents . . . .      (426)          371 
Cash and Cash Equivalents at Beginning of Period . . . . . .     1,381         1,106
Cash and Cash Equivalents at End of Period . . . . . . . . .  $    955      $  1,477

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was  $18,950,000 and $16,950,000
  and for income taxes was $5,812,000 and $8,115,000 in 1998 and 1997, respectively.
  Noncash acquisitions under capital leases  were $4,448,000 and $3,571,000  in 1998
  and 1997, respectively.

</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
                      KENTUCKY POWER COMPANY
                  NOTES TO FINANCIAL STATEMENTS
                        SEPTEMBER 30, 1998     
                           (UNAUDITED)
1.   GENERAL

         The accompanying unaudited financial statements should be
     read in conjunction with the 1997 Annual Report as incorporated
     in and filed with the Form 10-K.  In the opinion of management,
     the financial statements reflect all adjustments (consisting
     of only normal recurring accruals) which are necessary for a
     fair presentation of the results of operations and financial
     condition for interim periods.

2.   FINANCING ACTIVITIES

         The Company received from its parent a cash capital
     contribution of $10 million in June 1998 which was credited to
     paid-in capital.

3.   NEW ACCOUNTING STANDARDS

         Statement of Financial Accounting Standards (SFAS) No. 130
     "Reporting Comprehensive Income" was adopted by the Company in
     the first quarter of 1998.  SFAS No. 130 established the
     standards for reporting and displaying components of
     "comprehensive income," which is the total of net income and
     all transactions not included in net income affecting equity
     except those with shareholders.  For the quarter and year-to-date periods
     ended September 30, 1998, there were no material
     differences between comprehensive income and net income.

         In the first quarter of 1998 the Company adopted the
     American Institute of Certified Public Accountants' Statement
     of Position (SOP) 98-1, "Accounting for the Costs of Computer
     Software Developed or Obtained for Internal Use". The SOP
     requires the capitalization and amortization of certain costs
     of acquiring or developing internal use computer software. 
     Previously the Company expensed all software acquisition and
     development costs.  The SOP must be adopted at the beginning
     of a fiscal year with no restatement or retroactive adjustment
     of prior periods.  The adoption of the SOP effective January
     1, 1998 did not have a material effect on results of
     operations, cash flows or financial condition.

4.   POWER MARKETING AND TRADING

         During 1998, American Electric Power Service Corporation,
     as agent for the Company and its affiliates in the AEP System
     Power Pool (Power Pool), substantially increased the volume of
     its electricity marketing and trading.  The purpose of the
     power marketing and trading business is to utilize AEP's
     knowledge of the energy markets in order to improve the
     competitiveness of its generation business and contribute to
          net income.  Revenues and expenses from these activities are <PAGE>
<PAGE>
     shared by the Power Pool members based on their relative peak
     demands.

         The power marketing and trading business involves the
     marketing of power under physical forward contracts at fixed
     and variable prices and the trading of options, futures, swaps
     and other financial derivative contracts at both fixed and
     variable prices.  Most contracts represent physical forward
     electricity marketing contracts for the purchase and sale of
     electricity in the Power Pool's traditional marketing area
     which are recorded as operating revenues and purchased power
     expense  when the contracts settle.  At September 30, 1998, the
     Power Pool had open marketing contracts, not on the balance
     sheet, in its traditional marketing area through the year 2004
     to sell electricity with a notional value of approximately $1.1
     billion and to purchase electricity with a notional value of
     approximately $1.1 billion.  The Company's share of these
     notional values is approximately $70 million.

         The Power Pool has also purchased and sold electricity
     options, futures, and swaps, and entered into forward purchase
     and sale contracts for the future delivery or receipt of
     electricity outside its traditional marketing area.  These
     transactions represent non-regulated trading activities that
     are marked-to-market and recorded in nonoperating loss.  At
     September 30, 1998, the Company's share of the unrealized mark-to-market
     gains and losses from such trading contracts are
     reported as assets and liabilities, respectively.  At September
     30, 1998, the Power Pool had open marketing contracts outside
     its traditional marketing area through the year 2008 to sell
     electricity with a notional value of approximately $230 million
     and to purchase electricity with a notional value of
     approximately $145 million.  The Company's share of these
     notional values is approximately $15 million for sales and
     approximately $10 million for purchases.

         Dependent on future electricity market conditions these
     activities could produce material income or losses in future
     periods.

5.   CONTINGENCIES

     Taxes

         As discussed in Note 8, "Federal Income Taxes" of the Notes
     to Financial Statements in the 1997 Annual Report, the Internal
     Revenue Service (IRS) agents auditing the AEP System's
     consolidated federal income tax returns requested a ruling from
     their National Office that certain interest deductions relating
     to corporate owned life insurance (COLI) claimed by the Company
     should not be allowed.  As a result of a suit filed in United
     States District Court (discussed below) this request for ruling
     has been withdrawn.  Adjustments have been or will be proposed
     by the IRS disallowing COLI interest deductions for taxable
          years 1992-96.  A disallowance of COLI interest deductions<PAGE>
<PAGE>
     through September 30, 1998 would reduce earnings by
     approximately $7 million (including interest).  The Company has
     made no provision for any possible adverse earnings impact from
     this matter.

         In order to resolve this issue without further delay, on
     March 24, 1998, the Company filed suit against the United
     States in the United States District Court for the Southern
     District of Ohio.  Management believes that it has a
     meritorious position and will vigorously pursue this lawsuit. 
     In July 1998, the Company made a payment of taxes and interest
     attributable to COLI interest deductions for taxable years
     1992-96 to avoid the potential assessment by the IRS of any
     additional above market rate interest on the contested amount. 
     In September 1998 the Company made an additional payment for
     the 1997 tax year.  The payments were included on the balance
     sheet in other property and investments pending the resolution
     of this matter.  The Company will seek refund, either
     administratively or through litigation, of all amounts paid. 
     In the event the resolution of this matter is unfavorable, it
     will have a material adverse impact on results of operations
     and cash flows.

     Revised Air Quality Standards

         The United States Environmental Protection Agency (Federal
     EPA) published in October 1997 a proposed nitrogen oxides (NOx)
     emissions reduction rule which called for new state
     implementation plans (SIPs).  SIPs are a procedural method used
     by each state to comply with Federal EPA rules.  Eight
     northeastern states also filed petitions in 1997 with Federal
     EPA claiming NOx emissions from plants in midwestern states
     prevent them from complying with air quality standards.

         On September 24, 1998, Federal EPA issued final rules which
     require reductions in NOx emissions in 22 eastern states,
     including the states in which the Company's generating plants
     are located.  The implementation of the final rules would be
     achieved through the revision of SIPs by September 1999 that,
     by the year 2003, anticipate the imposition of a NOx reduction
     on utility sources of approximately 85% below 1990 emission
     levels.  On October 30, 1998, a number of utilities, including
     the Company and its affiliates in the AEP System, filed a
     petition in the U.S. Court of Appeals for the District of
     Columbia Circuit seeking a review of the final rules.

         Should the states fail to adopt the required revisions to
     their SIPs within one year of the date of the final rules
     (September 24, 1999), Federal EPA has proposed to implement a
     federal plan to accomplish the NOx reductions.  Federal EPA
     also proposed the approval of portions of the petitions filed
     by the eight northeastern states that would result in
     imposition of NOx emission reductions on utility and industrial
     sources.  These reductions are substantially the same as those
          required by the final rules and could be adopted by Federal EPA
<PAGE>
<PAGE>
     in the event the states fail to implement SIPs in accordance
     with the final rules.

         Based on initial studies, preliminary estimates indicate
     that compliance costs could result in capital expenditures of
     approximately $105 million.  Compliance costs can not be
     estimated with certainty and the actual costs incurred to
     comply could be significantly different from the preliminary
     estimate depending upon the compliance alternatives selected
     to achieve reductions in NOx emissions.  Unless such costs are
     recovered from customers, they would have a material adverse
     effect on results of operations, cash flows and possibly
     financial condition.

     Other

         The Company continues to be involved in certain other
     matters discussed in its 1997 Annual Report.

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

            THIRD QUARTER 1998 vs. THIRD QUARTER 1997
                               AND
             YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
     Net income increased $4 million or 90% for the quarter and
decreased $0.9 million or 5% for the year-to-date period.  The
increase in net income for the quarter is attributable to an
increase in retail and wholesale revenues reflecting increased
sales.  The decline in year-to-date net income is due to increased
maintenance and interest costs.
     The significant changes in income statement line items and net
revenues were:
                                    Increase (Decrease)         
                            Third Quarter        Year-to-Date   
                          (in millions)  %   (in millions)    % 

Operating Revenues. . . . .  $192.5     214     $315.3       123
Fuel Expense. . . . . . . .     1.5       7        3.3         6
Purchased Power Expense . .   180.3     N.M.     301.6       409
  Net Revenues                 10.7               10.4
Maintenance Expense . . . .     1.2      19        6.9        41
Depreciation and
  Amortization. . . . . . .     0.4       6        1.2         6
Federal Income Taxes. . . .     2.8     152       (0.2)       (3)
Nonoperating Loss . . . . .    (0.8)    N.M.      (0.7)      N.M.
Interest Charges. . . . . .     0.9      14        2.9        16

N.M. = Not Meaningful

     The substantial increases in operating revenues for the third
quarter and year-to-date periods were due primarily to increased
sales volume.  Retail revenues increased 4% in the third quarter
and 2% year-to-date reflecting the impact of warmer summer weather
on retail usage.  Wholesale revenues increased in both periods due
to growth in the power marketing and trading business which
contributed substantially to an increase in wholesale sales.
     Fuel expense increased due to additional generation to meet the
increase in demand and an increase in the cost of coal.
     The significant increase in purchased power expense resulted
from the growth of the power marketing and trading business.
<PAGE>
<PAGE>
     Net revenues increased $10.7 million in the third quarter and
$10.4 million in the year-to-date period due to increased retail
sales reflecting the impact of warmer summer weather and the
successful trading of wholesale energy in a volatile market.
     The increase in maintenance expense in both periods reflects
the effects of scheduled steam plant maintenance work in 1998 at
the Company's Big Sandy Plant and, for the year-to-date period,
expenditures for repair and restoration of distribution service
caused by two severe snowstorms.
     Depreciation and amortization expense increased due to
additional investment in depreciable plant reflecting improvements
to the transmission and distribution systems completed during 1997.
     The increase in federal income taxes for the third quarter
resulted from an increase in pre-tax operating income.
     Nonoperating income declined due to losses on certain power
marketing and trading transactions.  These transactions, which are
marked-to-market and described in footnote 4, represent non-regulated
trading activities outside the Company's traditional
marketing area.  Although losses were incurred on these non-regulated energy
trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.
     The increase in interest charges reflects an increase in
outstanding long-term debt due to the issuance of Senior Unsecured
Notes in October 1997.
<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                          Three Months Ended         Nine Months Ended
                                             September 30,             September 30,     
                                           1998        1997          1998         1997
                                                         (in thousands)
<S>                                      <C>         <C>          <C>          <C>
OPERATING REVENUES . . . . . . . . . . . $1,361,336  $486,398     $2,901,072   $1,417,845
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    199,934   156,482        574,156      462,720
  Purchased Power. . . . . . . . . . . .    824,021    37,270      1,392,404       69,738
  Other Operation. . . . . . . . . . . .     96,254    78,623        260,097      240,182
  Maintenance. . . . . . . . . . . . . .     34,900    39,443         98,651      102,292
  Depreciation and Amortization. . . . .     36,236    35,323        108,097      105,351
  Taxes Other Than Federal Income Taxes.     42,931    42,938        127,451      126,801
  Federal Income Taxes . . . . . . . . .     38,222    27,203        102,444       92,022

          TOTAL OPERATING EXPENSES . . .  1,272,498   417,282      2,663,300    1,199,106
OPERATING INCOME . . . . . . . . . . . .     88,838    69,116        237,772      218,739
NONOPERATING INCOME (LOSS) . . . . . . .     (2,665)    2,273          2,022        9,803
INCOME BEFORE INTEREST CHARGES . . . . .     86,173    71,389        239,794      228,542
INTEREST CHARGES . . . . . . . . . . . .     20,212    20,718         60,338       61,961
NET INCOME . . . . . . . . . . . . . . .     65,961    50,671        179,456      166,581
PREFERRED STOCK DIVIDEND REQUIREMENTS. .        369       370          1,107        2,278
EARNINGS APPLICABLE TO COMMON STOCK. . . $   65,592  $ 50,301     $  178,349   $  164,303

                                                                    

               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended         Nine Months Ended
                                             September 30,             September 30,     
                                           1998        1997          1998         1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $597,357    $573,236     $590,151       $584,015
NET INCOME . . . . . . . . . . . . . . .   65,961      50,671      179,456        166,581
DEDUCTIONS:  
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   52,775      37,562      158,325        161,771
    Cumulative Preferred Stock . . . . .      369         370        1,108          2,829
  Capital Stock Expense. . . . . . . . .     -           -            -                21

BALANCE AT END OF PERIOD . . . . . . . . $610,174    $585,975     $610,174       $585,975

The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1998            1997    
                                                                 (in thousands)
ASSETS
<S>                                                        <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,636,368      $2,606,981
  Transmission . . . . . . . . . . . . . . . . . . . .        841,410         837,953
  Distribution . . . . . . . . . . . . . . . . . . . .        938,470         927,239
  General (including mining assets). . . . . . . . . .        686,593         709,475
  Construction Work in Progress. . . . . . . . . . . .        103,453          74,149
          Total Electric Utility Plant . . . . . . . .      5,206,294       5,155,797
  Accumulated Depreciation and Amortization. . . . . .      2,425,511       2,349,995

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,780,783       2,805,802


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        219,677         113,279


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         95,620          44,203
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .        329,254         196,982
    Affiliated Companies . . . . . . . . . . . . . . .         73,956          55,597
    Miscellaneous. . . . . . . . . . . . . . . . . . .         20,884          43,594
    Allowance for Uncollectible Accounts . . . . . . .         (1,838)         (2,501)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         87,763         119,543
  Materials and Supplies . . . . . . . . . . . . . . .         84,433          80,853
  Accrued Utility Revenues . . . . . . . . . . . . . .         43,900          37,586
  Prepayments. . . . . . . . . . . . . . . . . . . . .         37,905          37,257

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        771,877         613,114



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        528,068         523,891


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         46,127         107,116



            TOTAL. . . . . . . . . . . . . . . . . . .     $4,346,532      $4,163,202
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1998            1997    
                                                                 (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. . . . . . . . . . . . . . . . . . .        462,314         462,296
  Retained Earnings. . . . . . . . . . . . . . . . . .        610,174         590,151
          Total Common Shareholder's Equity. . . . . .      1,393,689       1,373,648
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .         17,471          17,542
    Subject to Mandatory Redemption. . . . . . . . . .         11,850          11,850
  Long-term Debt . . . . . . . . . . . . . . . . . . .      1,027,587       1,012,031

          TOTAL CAPITALIZATION . . . . . . . . . . . .      2,450,597       2,415,071

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        315,114         295,375

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .         16,289          83,195
  Short-term Debt. . . . . . . . . . . . . . . . . . .         98,808          78,700
  Accounts Payable - General . . . . . . . . . . . . .        286,042         146,824
  Accounts Payable - Affiliated Companies. . . . . . .         44,392          37,923
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .        114,435         160,055
  Interest Accrued . . . . . . . . . . . . . . . . . .         22,165          16,255
  Obligations Under Capital Leases . . . . . . . . . .         27,994          30,307
  Other. . . . . . . . . . . . . . . . . . . . . . . .        114,733          94,829

          TOTAL CURRENT LIABILITIES. . . . . . . . . .        724,858         648,088

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .        723,718         723,172

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .         40,293          42,821

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .         91,952          38,675

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .     $4,346,532      $4,163,202
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                  Nine Months Ended
                                                                    September 30,     
                                                                 1998           1997
                                                                    (in thousands)
<S>                                                           <C>            <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 179,456      $ 166,581
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . .    129,366        129,597
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     12,504             85
    Amortization of Deferred Property Taxes. . . . . . . . .     58,664         57,646
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .   (128,584)        (9,892)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     28,200         (5,112)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     (6,314)        10,044
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    145,687         34,712
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (45,620)       (80,111)
    Other Current Assets and Current Liabilities . . . . . .     22,853         31,267
  Payment of Disputed Tax and Interest Related to COLI . . .   (104,222)          -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     68,381        (24,047)
        Net Cash Flows From Operating Activities . . . . . .    360,371        310,770

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (121,310)      (102,469)
  Proceeds from Sale of Property and Other . . . . . . . . .      4,348          8,553
        Net Cash Flows Used For Investing Activities . . . .   (116,962)       (93,916)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    137,566        146,589
  Change in Short-term Debt (net). . . . . . . . . . . . . .     20,108         53,123
  Retirement of Cumulative Preferred Stock . . . . . . . . .        (52)      (117,601)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (190,181)      (119,542)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (158,325)      (161,771)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,108)        (2,829)
        Net Cash Flows Used For Financing Activities . . . .   (191,992)      (202,031)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     51,417         14,823
Cash and Cash Equivalents at Beginning of Period . . . . . .     44,203         24,003
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  95,620      $  38,826

Supplemental Disclosure:
  Cash paid for  interest net  of capitalized amounts was  $52,523,000 and $54,010,000
  and for income taxes was $55,898,000 and $98,341,000 in 1998 and 1997, respectively.
  Noncash acquisitions  under capital leases  were $24,740,000 and $41,677,000 in 1998
  and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
               OHIO POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        SEPTEMBER 30, 1998            
                           (UNAUDITED)
1.   GENERAL

         The accompanying unaudited consolidated financial statements 
should be read in conjunction with the 1997 Annual Report
     as incorporated in and filed with the Form 10-K.  In the
     opinion of management, the financial statements reflect all
     adjustments (consisting of only normal recurring accruals)
     which are necessary for a fair presentation of the results of
     operations and financial condition for interim periods.

2.   FINANCING ACTIVITY

         In April 1998 the Company issued $140 million of 7-3/8%
     senior unsecured notes due 2038.  During the first nine months
     of 1998 the Company and a subsidiary retired $183 million of
     long-term debt: $56 million  of 6-3/4% first mortgage bonds and
     $17 million of 6.85% notes payable at maturity and two series
     of $50 million first mortgage bonds due in 2002 with interest
     rates of 8.10% and 8.25% and $10 million of variable rate notes
     payable due in 1999.

         As a result of the redemption of the 6-3/4% series first
     mortgage bonds due in 1998, the restriction on the use of
     retained earnings for the payment of common stock dividends was
     eliminated.

3.   NEW ACCOUNTING STANDARDS

         Statement of Financial Accounting Standards (SFAS) No. 130
     "Reporting Comprehensive Income" was adopted by the Company in
     the first quarter of 1998.  SFAS No. 130 established the
     standards for reporting and displaying components of
     "comprehensive income," which is the total of net income and
     all transactions not included in net income affecting equity
     except those with shareholders.  For the quarter and year-to-date periods
     ended September 30, 1998, there are no material
     differences between comprehensive income and net income.

         In the first quarter of 1998 the Company adopted the
     American Institute of Certified Public Accountants' Statement
     of Position (SOP) 98-1, "Accounting for the Costs of Computer
     Software Developed or Obtained for Internal Use." The SOP
     requires the capitalization and amortization of certain costs
     of acquiring or developing internal use computer software. 
     Previously the Company expensed all software acquisition and
     development costs.  The SOP must be adopted at the beginning
     of a fiscal year with no restatement or retroactive adjustment
     of prior periods.  The adoption of the SOP effective January
     1, 1998 did not have a material effect on results of
     operations, cash flows or financial condition.
<PAGE>
<PAGE>
4.   POWER MARKETING AND TRADING

         During 1998, American Electric Power Service Corporation,
     as agent for the Company and its affiliates in the AEP System
     Power Pool (Power Pool), substantially increased the volume of
     its electricity marketing and trading.  The purpose of the
     power marketing and trading business is to utilize AEP's
     knowledge of the energy markets in order to improve the
     competitiveness of its generation business and contribute to
     net income.  Revenues and expenses from these activities are
     shared by the Power Pool members based on their relative peak
     demands.

         The power marketing and trading business involves the
     marketing of power under physical forward contracts at fixed
     and variable prices and the trading of options, futures, swaps
     and other financial derivative contracts at both fixed and
     variable prices.  Most contracts represent physical forward
     electricity marketing contracts for the purchase and sale of
     electricity in the Power Pool's traditional marketing area
     which are recorded as operating revenues and purchased power
     expense  when the contracts settle.  At September 30, 1998, the
     Power Pool had open marketing contracts, not on the balance
     sheet, in its traditional marketing area through the year 2004
     to sell electricity with a notional value of approximately $1.1
     billion and to purchase electricity with a notional value of
     approximately $1.1 billion.  The Company's share of these
     notional values is approximately $290 million.

         The Power Pool has also purchased and sold electricity
     options, futures, and swaps, and entered into forward purchase
     and sale contracts for the future delivery or receipt of
     electricity outside the traditional marketing area.  These
     transactions represent non-regulated trading activities that
     are marked-to-market and recorded in nonoperating income.  At
     September 30, 1998, the Company's share of the unrealized mark-to-market
     gains and losses from such trading contracts are
     reported as assets and  liabilities, respectively.  At
     September 30, 1998, the Power Pool had open marketing contracts
     outside its traditional marketing area through the year 2008
     to sell electricity with a notional value of approximately $230
     million and to purchase electricity with a notional value of
     approximately $145 million.  The Company's share of these
     notional values is approximately $65 million for sales and
     approximately $40 million for purchases.

         Dependent on future electricity market conditions these
     activities could produce material income or losses in future
     periods.
<PAGE>
<PAGE>
5.   CONTINGENCIES

     Taxes

         As discussed in Note 8, "Federal Income Taxes" of the Notes
     to Consolidated Financial Statements in the 1997 Annual Report,
     the Internal Revenue Service (IRS) agents auditing the AEP
     System's consolidated federal income tax returns requested a
     ruling from their National Office that certain interest
     deductions relating to corporate owned life insurance (COLI)
     claimed by the Company should not be allowed.  As a result of
     a suit filed in United States District Court (discussed below)
     this request for ruling has been withdrawn.  Adjustments have
     been or will be proposed by the IRS disallowing COLI interest
     deductions for taxable years 1991-96.  A disallowance of the
     COLI interest deduction through September 30, 1998 would reduce
     earnings by approximately $115 million (including interest). 
     The Company has made no provision for any possible adverse
     earnings impact from this matter.

         In order to resolve this issue without further delay, on
     March 24, 1998, the Company filed suit against the United
     States in the United States District Court for the Southern
     District of Ohio.  Management believes that it has a
     meritorious position and will vigorously pursue this lawsuit. 
     In July 1998 the Company made a payment of taxes and interest
     attributable to COLI interest deductions for taxable years
     1991-96 to avoid the potential assessment by the IRS of any
     additional above market rate interest on the contested amount. 
     In September 1998 the Company made an additional payment for
     the 1997 tax year.  The payments were included on the balance
     sheet in other property and investments pending the resolution
     of this matter.  The Company will seek refund, either
     administratively or through litigation, of all amounts paid. 
     In the event the resolution of this matter is unfavorable, it
     will have a material adverse impact on results of operations
     and cash flows.

     Revised Air Quality Standards

         The United States Environmental Protection Agency (Federal
     EPA) published in October 1997 a proposed nitrogen oxides (NOx)
     emissions reduction rule which called for new state
     implementation plans (SIPs).  SIPs are a procedural method used
     by each state to comply with Federal EPA rules.  Eight
     northeastern states also filed petitions in 1997 with Federal
     EPA claiming NOx emissions from plants in midwestern states
     prevent them from complying with air quality standards.

         On September 24, 1998, Federal EPA issued final rules which
     require reductions in NOx emissions in 22 eastern states,
     including the states in which the Company's generating plants
     are located.  The implementation of the final rules would be
     achieved through the revision of SIPs by September 1999 that,
     by the year 2003, anticipate the imposition of a NOx reduction
          on utility sources of approximately 85% below 1990 emission <PAGE>
<PAGE>
     levels.  On October 30, 1998, a number of utilities, including
     the Company and its affiliates in the AEP System, filed a
     petition in the U.S. Court of Appeals for the District of
     Columbia Circuit seeking a review of the final rules.

         Should the states fail to adopt the required revisions to
     their SIPs within one year of the date of the final rules
     (September 24, 1999), Federal EPA has proposed to implement a
     federal plan to accomplish the NOx reductions.  Federal EPA
     also proposed the approval of portions of the petitions filed
     by the eight northeastern states that would result in
     imposition of NOx emission reductions on utility and industrial
     sources.  These reductions are substantially the same as those
     required by the final rules and could be adopted by Federal EPA
     in the event the states fail to implement SIPs in accordance
     with the final rules.

         Based on initial studies, preliminary estimates indicate
     that compliance costs could result in required capital
     expenditures by the Company of approximately $452 million. 
     Compliance costs can not be estimated with certainty and the
     actual costs incurred to comply could be significantly
     different from the preliminary estimate depending upon the
     compliance alternatives selected to achieve reductions in NOx
     emissions.  Unless such costs are recovered from customers,
     they would have a material adverse effect on results of
     operations, cash flows and possibly financial condition.

     Other

         The Company continues to be involved in certain other
     matters discussed in the 1997 Annual Report.

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

            THIRD QUARTER 1998 vs. THIRD QUARTER 1997
                               AND
             YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
RESULTS OF OPERATIONS
     Net income increased $15.3 million or 30% for the quarter and
$12.9 million or 8% for the year-to-date period primarily due to
increased energy sales to retail customers, reflecting warmer
summer weather and increased industrial energy consumption, and
growth in wholesale power marketing and trading activities.
     The significant changes in income statement line items and net
revenues were:
                                    Increase (Decrease)          
                             Third Quarter       Year-to-Date    
                          (in millions)   %   (in millions)    % 

Operating Revenues. . . .    $874.9     180     $1,483.2     105
Fuel Expense. . . . . . .      43.5      28        111.4      24
Purchased Power . . . . .     786.8     N.M.     1,322.7     N.M.
  Net Revenues. . . . . .      44.6                 49.1
Other Operation Expense .      17.6      22         19.9       8
Maintenance Expense . . .      (4.5)    (12)        (3.6)     (4)
Federal Income Taxes. . .      11.0      41         10.4      11
Nonoperating Income . . .      (4.9)   (217)        (7.8)    (79)

N.M. = Not Meaningful

     Operating revenues increased significantly in both the third
quarter and year-to-date periods due predominantly to increased 
retail and wholesale sales.  Retail sales increased 6% in the third
quarter and 4% year-to-date reflecting warmer summer weather in
1998 and the resumption of operations by a major industrial
customer following an extended labor strike.  Operating revenues
from wholesale sales increased significantly as a result of growth
in power marketing and trading activities and increased sales to
the AEP System Power Pool (Power Pool) to replace power previously
generated at an affiliate's nuclear plant which was out of service.
<PAGE>
<PAGE>
     The increases in fuel expense for the third quarter and year-to-date 
periods were mainly due to an increase in generation,
reflecting the rise in demand and the replacement of energy
previously supplied to the Power Pool by an affiliate's out-of-service 
nuclear plant, and an increase in the cost of fuel
consumed.
     Purchased power expense increased substantial for both periods
primarily due to the growth of power marketing and trading
activities.
     The increase in net revenues of $45 million in the third
quarter and $49 million in the year-to-date period reflects the
impact of warmer summer weather and increased industrial usage on
retail sales and the successful trading of wholesale energy in a
volatile market.
     Other operation expense increased in both periods primarily due
to costs related to the increase in energy sales, employer pension
and benefit expense, a reduction in gains on emission allowance
sales and increased costs under the AEP System transmission
equalization agreement.  The transmission equalization agreement
combines certain AEP System companies' investment in transmission
facilities and shares the costs of ownership of those facilities in
proportion to each AEP System company's peak demand relative to the
peak demands of all AEP System companies utilizing the AEP System
transmission system.  The charges paid by the Company under the
agreement increased due to an increase in the Company's prior
twelve month peak demand relative to the total peak demand of all
transmission agreement members.
     The decreases in maintenance expense for both periods were
mainly due to decreased boiler plant maintenance reflecting a
reduction in planned maintenance work on the Company's generating
units.
     Federal income taxes attributable to operations increased due
to an increase in pre-tax operating income.
<PAGE>
<PAGE>
     The decrease in nonoperating income is primarily due to losses
on certain power marketing and trading transactions.  These
transactions, which are marked-to-market and described in footnote
4, represent non-regulated trading activities outside the Company's
traditional marketing area.  Although losses were incurred on these
non-regulated energy trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.
FINANCIAL CONDITION
     Total plant and property additions including capital leases for
the first nine months of 1998 were $146 million.
     During the first nine months of 1998, the Company and a
subsidiary retired $183 million principal amount of long-term debt
with interest rates ranging from 6.11% to 8.25%, issued $140
million of senior unsecured notes at an interest rate of 7-3/8% and
increased short-term debt by $20 million.
     As a result of the redemption of the 6-3/4% series first
mortgage bonds due in 1998, the restriction on the use of retained
earnings for the payment of common stock dividends was eliminated.
REVISED AIR QUALITY STANDARDS
     The United States Environmental Protection Agency (Federal EPA)
published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state implementation
plans (SIPs).  SIPs are a procedural method used by each state to
comply with Federal EPA rules.  Eight northeastern states also
filed petitions in 1997 with Federal EPA claiming NOx emissions
from plants in midwestern states prevent them from complying with
air quality standards.
     On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states, including
the states in which the Company's generating plants are located. 
The implementation of the final rules would be achieved through the
revision of SIPs by September 1999 that, by the year 2003,
anticipate the imposition of a NOx reduction on utility sources of
approximately 85% below 1990 emission levels.  On October 30, 1998,
a number of utilities, including the Company and its affiliates in
the AEP System, filed a petition in the U.S. Court of Appeals for <PAGE>
<PAGE>
the District of Columbia Circuit seeking a review of the final
rules.
     Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions.  Federal EPA also proposed the
approval of portions of the petitions filed by the eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources.  These reductions are
substantially the same as those required by the final rules and
could be adopted by Federal EPA in the event the states fail to
implement SIPs in accordance with the final rules.
     Based on initial studies, preliminary estimates indicate that
compliance costs could result in required capital expenditures by
the Company of approximately $452 million.  Compliance costs can
not be estimated with certainty and the actual costs incurred to
comply could be significantly different from the preliminary
estimate depending upon the compliance alternatives selected to
achieve reductions in NOx emissions.  Unless such costs are
recovered from customers, they would have a material adverse effect
on results of operations, cash flows and possibly financial
condition.
COMPUTER ISSUE - YEAR 2000
     On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems were 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-Year
2000 ready programs.

<PAGE>
<PAGE>
     Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Year 2000-related failures and repair such failures if they occur. 
This includes both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), 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 Year 2000 readiness.
     Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system. 
AEP, along with other electric utilities in North America,
regularly submits information to the North American Electric
Reliability Council (NERC) as part of NERC's Year 2000 readiness
program.  NERC then publicly reports summary information to the
U.S. Department of Energy regarding the Year 2000 readiness of
electric utilities.  In 1999 AEP plans to participate in two
NERC-sponsored coordinated electric industry Year 2000 readiness
drills.
     The first NERC report, dated September 17, 1998 and titled
Preparing the Electric Power Systems of North America for
Transition to the Year 2000-A Status Report and Work Plan, states
that: "Mission critical systems and components are to be made Y2K
Ready by June 30, 1999."  In addition, the report indicates that:
"While many organizations are on track to meet these targets, many
others need to accelerate project plans and resources."  In
response to the report, the Company has accelerated its Year 2000
readiness date for mission critical and high priority systems and
components from September 30 to June 30, 1999.
     Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems.  Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.<PAGE>
<PAGE>
     Various state commissions are also reviewing the Year 2000
readiness of electric utilities subject to their jurisdiction.

     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,
communications, and the physical generation and delivery of energy;
followed by back office activities such as customer
service/billing, regulatory reporting, internal reporting and
administrative activities (e.g. payroll, procurement, accounts
payable); and finally, those activities that would cause
inconvenience or productivity loss in normal business operations.

     The following chart shows our progress toward becoming ready
for the Year 2000 as of September 30, 1998:
                             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%         11/30/1998    86%
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     2%
replacing or retiring                     60%
those mission critical and                         
high priority digital-based               Client
systems with problems                     Server:
processing dates past the                 1%        
Year 2000. Testing these
systems to ensure that after              
modifications have been                   
implemented correct date                  
processing occurs and full
functionality has been maintained.
<PAGE>
<PAGE>
     Costs to Address the Company's Year 2000 Issues - Through
September 30, 1998, the Company has spent $5 million on the Year
2000 project and, estimates spending an additional $12 million to
$16 million to achieve Year 2000 readiness.  Most Year 2000 costs
are software- and salary-related and are expensed; however, in
certain cases the Company has acquired hardware that is
capitalized.  The Company intends to fund these expenditures
through internal sources.  Although significant, the cost of
becoming Year 2000 ready 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 Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Year 2000 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.

     In addition, although as discussed 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.
<PAGE>
<PAGE>
     Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others not affiliated with AEP, fail for critical
applications, Year 2000-related issues may materially adversely
affect AEP.

     Company's Contingency Plans - The Company intends to establish
contingency plans on a case-by-case basis to address alternatives
if Year 2000 failures of automatic systems and equipment occur as
part of its Year 2000 readiness program.  The contingency plans
will be based upon a risk analysis process and will be developed by
the fourth quarter of 1999.  These plans will build upon disaster
recovery, system restoration, and contingency planning that we now
have in place.  We have begun the contingency planning process,
including the review of NERC's contingency planning and
preparations guide.  The Company plans to submit a draft of its
contingency plans to NERC as part of NERC's review of drafts of
regional and individual electric utility contingency plans in 1999.

     Forward-Looking Statements - This description of Year 2000
problems, the consequences of Year 2000 failures and the estimated
costs of, and timetable for, becoming Year 2000 ready constitute
"forward looking statements" as defined in the Private Securities
Litigation Reform Act of 1995.  Such statements are based on
management's beliefs as well as assumptions made by, and
information currently available to, management.  Investors are
cautioned that such statements and estimates could differ
materially from actual results because of factors referred to
specifically in connection with such forward-looking statements
and, in addition, the following other factors, among others:
<PAGE>
<PAGE>
     *   Continuing availability of experienced consultants and IT
         personnel and related resources
     *   Ability of third parties to complete their Year 2000
         remediations on a timely basis and accuracy of
         representations made by such third parties concerning
         their Year 2000 readiness
     *   Ability of the Company to identify and implement
         contingency plans.
TAXES
     As discussed in Note 8, "Federal Income Taxes" of the Notes to
Consolidated Financial Statements in the 1997 Annual Report, the
Internal Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from
their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company should
not be allowed.  As a result of a suit filed in United States
District Court (discussed below) this request for ruling has been
withdrawn.  Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions for taxable years 1991-96.  A
disallowance of the COLI interest deduction through September 30,
1998 would reduce earnings by approximately $115 million (including
interest).  The Company has made no provision for any possible
adverse earnings impact from this matter.
     In order to resolve this issue without further delay, on March
24, 1998, the Company filed suit against the United States in the
United States District Court for the Southern District of Ohio. 
Management believes that it has a meritorious position and will
vigorously pursue this lawsuit.  In July 1998 the Company made a
payment of taxes and interest attributable to COLI interest
deductions for taxable years 1991-96 to avoid the potential
assessment by the IRS of any additional above market rate interest
on the contested amount.  In September 1998 the Company made an
additional payment for the 1997 tax year.  The payments were
included on the balance sheet in other property and investments
pending the resolution of this matter.  The Company will seek
refund, either administratively or through litigation, of all
amounts paid.  In the event the resolution of this matter is <PAGE>
<PAGE>
unfavorable, it will have a material adverse impact on results of
operations and cash flows.
POWER MARKETING AND TRADING
     During 1998, American Electric Power Service Corporation, as
agent for the Company and its affiliates in the AEP System Power
Pool (Power Pool), substantially increased the volume of its
electricity marketing and trading.  The purpose of the power
marketing and trading business is to utilize AEP's knowledge of the
energy markets in order to improve the competitiveness of its
generation business and contribute to net income.  Revenues and
expenses from these activities are shared by the Power Pool members
based on their relative peak demands.
     The power marketing and trading business involves the marketing
of power under physical forward contracts at fixed and variable
prices and the trading of options, futures, swaps and other
financial derivative contracts at both fixed and variable prices. 
Most contracts represent physical forward electricity marketing
contracts for the purchase and sale of electricity in the Power
Pool's traditional marketing area which are recorded as operating
revenues and purchased power expense  when the contracts settle. 
At September 30, 1998, the Power Pool had open marketing contracts,
not on the balance sheet, in its traditional marketing area through
the year 2004 to sell electricity with a notional value of
approximately $1.1 billion and to purchase electricity with a
notional value of approximately $1.1 billion.  The Company's share
of these notional values is approximately $290 million.
     The Power Pool has also purchased and sold electricity options,
futures, and swaps, and entered into forward purchase and sale
contracts for the future delivery or receipt of electricity outside
the traditional marketing area.  These transactions represent non-regulated
trading activities that are marked-to-market and recorded
in nonoperating income.  At September 30, 1998, the Company's share
of the unrealized mark-to-market gains and losses from such trading
contracts are reported as assets and liabilities, respectively.  At
September 30, 1998, the Power Pool had open marketing contracts
outside its traditional marketing area through the year 2008 to
sell electricity with a notional value of approximately $230 <PAGE>
<PAGE>
million and to purchase electricity with a notional value of
approximately $145 million.  The Company's share of these notional
values is approximately $65 million for sales and approximately $40
million for purchases.
     Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
<PAGE>
                   PART II.  OTHER INFORMATION

Item 5.  Other Information.

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

     The deadline for submission of shareholder proposals pursuant
to Rule 14a-8 under the Securities Exchange Act of 1934, as
amended, ("Rule 14a-8"), for inclusion in AEP's proxy statement for
its 1999 Annual Meeting of Shareholders was November 10, 1998. 
After February 1, 1999, notice to AEP of a shareholder proposal
submitted otherwise than pursuant to Rule 14a-8 will be considered
untimely, and the persons named in proxies solicited by AEP's Board
of Directors for its 1999 Annual Meeting of Shareholders may
exercise discretionary voting power with respect to any such
proposal as to which AEP does not receive timely notice.

AEP and Appalachian Power Company ("APCo")

     Reference is made to page 10 of the Annual Report on Form 10-K
for the year ended December 31, 1997 ("1997 10-K") and page II-1 of
the Quarterly Report on Form 10-Q for the quarter ended March 31,
1998, for a discussion of retail competition in Virginia.  Pursuant
to an order of the Virginia State Corporation Commission ("Virginia
SCC"),  APCo filed its Customer Choice Pilot Program with the
Virginia SCC on November 2, 1998.  The Virginia SCC must approve
the program before it becomes effective.  The proposed two-year
program would give approximately 3,200 APCo retail customers in
Virginia--residential, commercial and industrial--an opportunity to
choose an Energy Service Provider ("ESP") of generation service
other than APCo.  ESPs include marketers, brokers and aggregators
who provide generation service at unregulated prices.  If a
participating customer were to pick an ESP for generation service,
APCo would continue to provide distribution and transmission
service.  Participation would be open to 2% or 50 megawatts of
APCo's Virginia load.

     Reference is made to pages 12 and 13 of the 1997 10-K and page
II-3 of the Quarterly Report on Form 10-Q for the quarter ended
June 30, 1998, for a discussion of APCo's proposed transmission
facilities. By Hearing Examiner's Ruling of June 9, 1998, the
procedural schedule for the certificate in Virginia was suspended
for 90 days to allow APCo to conduct additional studies.  On August
21, 1998, APCo filed a report stating that a two-phased alternative
project could provide electrical transmission reinforcement
comparable to the Wyoming-Cloverdale line.










                               II-1<PAGE>
     

By Hearing Examiner's Ruling of September 22, 1998, the
proceeding was continued and APCo was directed to study the first
phase of the alternative project, involving a line running from
Wyoming Station in West Virginia to APCo's existing Jacksons Ferry
Station in Virginia or any point on the Jacksons Ferry-Cloverdale
765kV transmission line.  APCo estimates that the Wyoming-Jacksons
Ferry line would be between 82-100 miles in length, including 32
miles in West Virginia previously certified.  APCo must file its
study by June 1, 1999.  The Hearing Examiner also ordered APCo and
the Virginia SCC Staff to provide at the evidentiary hearing
information on generation alternatives, specifically natural gas
generation, to APCo's proposed transmission line.

     Management estimates that the earliest APCo could complete
either the Wyoming-Cloverdale or Wyoming-Jacksons Ferry project is
the winter of 2003/2004.

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

     Reference is made to page 22 of the 1997 10-K for a discussion
of proposed revisions to the new source performance standard for
nitrogen oxides emissions from new utility and large industrial
boilers.  On September 3, 1998, the U.S. Environmental Protection
Agency issued final revisions to this standard.  The revised rule
specifies the emission limit for new sources in terms of output
rather than emission rate.  The emission limit is set at a level
which cannot currently be achieved by combustion controls and will
require the use of post combustion control equipment.  Imposition
of this standard to existing sources which might become subject to
the rule based on an administrative finding that an existing source
had been modified or reconstructed could result in substantial
capital and operating expenditures.

AEP and OPCo

     Reference is made to page 31 of the 1997 10-K for a discussion
of litigation with Ormet Corporation involving the ownership of
sulfur dioxide allowances.  In a letter dated August 27, 1998, the
U.S. District Court, Northern District of West Virginia, advised
the parties to the litigation that the court would issue an order
granting the motion for summary judgment filed by OPCo and the AEP
Service Corporation.












                               II-2
<PAGE>
Item 6.  Exhibits and Reports on Form 8-K.

     (a) Exhibits:

         AEP, APCo and OPCo

             Exhibit 10 - AEP System Survivor Benefit Plan,
             effective January 27, 1998.

         APCo, CSPCo, I&M, KEPCo and OPCo

             Exhibit 12 - Statement re: Computation of Ratios.

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

             Exhibit 27 - Financial Data Schedule.

     (b) Reports on Form 8-K:

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

         No reports on Form 8-K were filed during the quarter ended
         September 30, 1998. 
































                               II-3<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: November 12, 1998







                               II-4