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, 1999

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

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

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

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

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

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

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

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

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

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

The number of shares outstanding of American Electric Power Company, Inc. Common Stock,
par value $6.50, at October 31, 1999 was 194,103,349.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                               FORM 10-Q

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

                                                                          Page
Part I.  FINANCIAL INFORMATION
           <S>                                                            <C>
           American Electric Power Company, Inc. and Subsidiary Companies:
             Consolidated Statements of Income and
               Statements of Comprehensive Income . . . . . . . . . . . . A-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2 - A-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4
             Consolidated Statements of Retained Earnings . . . . . . . . A-5
             Notes to Consolidated Financial Statements . . . . . . . . . A-6 - A-21
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . A-22- A-43

           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-10
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . C-11- C-22

           Columbus Southern Power Company and Subsidiaries:
             Consolidated Statements of Income and
               Consolidated Statements of Retained Earnings . . . . . . . D-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . . D-2 - D-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . . D-4
             Notes to Consolidated Financial Statements . . . . . . . . . D-5 - D-10
             Management's Narrative Analysis of Results of Operations . . D-11- D-12

           Indiana Michigan Power Company and Subsidiaries:
             Consolidated Statements of Income and
               Consolidated Statements of Retained Earnings . . . . . . . E-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . . E-2 - E-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . . E-4
             Notes to Consolidated Financial Statements . . . . . . . . . E-5 - E-11
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . . E-12- E-24

           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
</TABLE>


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

                                        FORM 10-Q

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

                                                                        Page
           <S>                                                          <C>
           Ohio Power Company and Subsidiaries:
             Consolidated Statements of Income and
               Consolidated Statements of Retained Earnings . . . . . . G-1
             Consolidated Balance Sheets. . . . . . . . . . . . . . . . G-2 - G-3
             Consolidated Statements of Cash Flows. . . . . . . . . . . G-4
             Notes to Consolidated Financial Statements . . . . . . . . G-5 - G-12
             Management's Discussion and Analysis of Results of
               Operations and Financial Condition . . . . . . . . . . . G-13- G-25


Part II. OTHER INFORMATION

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

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

EXHIBITS INDEX. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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>



FORWARD-LOOKING INFORMATION

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

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


<PAGE>
<TABLE>
      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                     CONSOLIDATED STATEMENTS OF INCOME
                  (in millions, except per-share amounts)
                                (UNAUDITED)
<CAPTION>
                                             Three Months Ended      Nine Months Ended
                                                September 30,           September 30,
                                              1999        1998        1999        1998
<S>                                          <C>         <C>         <C>         <C>
REVENUES:
  Domestic Regulated Electric Utilities. .   $1,758      $1,846      $4,809      $4,916
  Worldwide Non-regulated Electric and
    Gas Operations . . . . . . . . . . . .      156          12         442          20

          TOTAL REVENUES . . . . . . . . .    1,914       1,858       5,251       4,936

EXPENSES:
  Fuel and Purchased Power . . . . . . . .      631         652       1,616       1,691
  Maintenance and Other Operation. . . . .      491         496       1,387       1,344
  Depreciation and Amortization. . . . . .      151         146         448         434
  Taxes Other Than Federal Income Taxes. .      121         120         364         354
  Worldwide Non-regulated Electric and
    Gas Operations . . . . . . . . . . . .      144          31         394          62

          TOTAL EXPENSES . . . . . . . . .    1,538       1,445       4,209       3,885
OPERATING INCOME . . . . . . . . . . . . .      376         413       1,042       1,051
NONOPERATING INCOME (LOSS) . . . . . . . .        3          (3)       -              6
INCOME BEFORE INTEREST, PREFERRED
  DIVIDENDS AND INCOME TAXES . . . . . . .      379         410       1,042       1,057

INTEREST AND PREFERRED DIVIDENDS . . . . .      136         110         403         325

INCOME BEFORE INCOME TAXES . . . . . . . .      243         300         639         732

INCOME TAXES . . . . . . . . . . . . . . .       69         105         226         268

NET INCOME . . . . . . . . . . . . . . . .   $  174      $  195      $  413      $  464

AVERAGE NUMBER OF SHARES OUTSTANDING . . .      194         191         193         191

EARNINGS PER SHARE . . . . . . . . . . . .    $0.90       $1.02       $2.14       $2.44

CASH DIVIDENDS PAID PER SHARE. . . . . . .    $0.60       $0.60       $1.80       $1.80



              CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                             Three Months Ended      Nine Months Ended
                                                September 30,           September 30,
                                              1999        1998        1999        1998

NET INCOME . . . . . . . . . . . . . . . .    $174        $195        $413        $464

OTHER COMPREHENSIVE INCOME:
  Foreign Currency Translation
    Adjustments. . . . . . . . . . . . . .      (1)         -           20          -
COMPREHENSIVE INCOME . . . . . . . . . . .    $173        $195        $433        $464

See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                               1999           1998
                                                                 (in millions)
ASSETS
<S>                                                          <C>            <C>
CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .       $   274        $   173
  Accounts Receivable (net). . . . . . . . . . . . . .           978            879
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .           297            216
  Materials and Supplies . . . . . . . . . . . . . . .           307            280
  Accrued Utility Revenues . . . . . . . . . . . . . .           213            214
  Energy Marketing and Trading Contracts . . . . . . .           666            372
  Prepayments and Other. . . . . . . . . . . . . . . .            93             84

          TOTAL CURRENT ASSETS . . . . . . . . . . . .         2,828          2,218

PROPERTY, PLANT AND EQUIPMENT:
  Electric:
    Production . . . . . . . . . . . . . . . . . . . .         9,902          9,615
    Transmission . . . . . . . . . . . . . . . . . . .         3,793          3,692
    Distribution . . . . . . . . . . . . . . . . . . .         5,349          5,125
  Other (including gas and coal mining assets
   and nuclear fuel) . . . . . . . . . . . . . . . . .         2,259          2,118
  Construction Work in Progress. . . . . . . . . . . .           661            801
          Total Property, Plant and Equipment. . . . .        21,964         21,351
  Accumulated Depreciation and Amortization. . . . . .         9,043          8,549


          NET PROPERTY, PLANT AND EQUIPMENT. . . . . .        12,921         12,802



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         2,049          1,847



OTHER ASSETS . . . . . . . . . . . . . . . . . . . . .         2,640          2,616


            TOTAL. . . . . . . . . . . . . . . . . . .       $20,438        $19,483

See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                         September 30,    December 31,
                                                              1999            1998
                                                                 (in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S>                                                         <C>             <C>
CURRENT LIABILITIES:
  Accounts Payable . . . . . . . . . . . . . . . . . .      $   647         $   607
  Short-term Debt. . . . . . . . . . . . . . . . . . .          710             617
  Long-term Debt Due Within One Year . . . . . . . . .          978             206
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .          239             382
  Interest Accrued . . . . . . . . . . . . . . . . . .          117              75
  Obligations Under Capital Leases . . . . . . . . . .           90              82
  Energy Marketing and Trading Contracts . . . . . . .          643             360
  Other. . . . . . . . . . . . . . . . . . . . . . . .          483             472

          TOTAL CURRENT LIABILITIES. . . . . . . . . .        3,907           2,801

LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . .        6,219           6,800

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .        2,647           2,601

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .          334             351

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .          215             222

DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . .          424             263

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        1,503           1,429

CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES . . . . . .          169             174

CONTINGENCIES (Note 9)

COMMON SHAREHOLDERS' EQUITY:
  Common Stock-Par Value $6.50:
                                1999          1998
    Shares Authorized . . . .600,000,000   600,000,000
    Shares Issued . . . . . .203,092,805   200,816,469
    (8,999,992 shares were held in treasury) . . . . .        1,320           1,305
  Paid-in Capital. . . . . . . . . . . . . . . . . . .        1,931           1,854
  Accumulated Other Comprehensive Income -
   Foreign Currency Translation Adjustments. . . . . .           19              (1)
  Retained Earnings. . . . . . . . . . . . . . . . . .        1,750           1,684

          TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . .        5,020           4,842

            TOTAL. . . . . . . . . . . . . . . . . . .      $20,438         $19,483

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                   Nine Months Ended
                                                                     September 30,
                                                                 1999             1998
                                                                     (in millions)
<S>                                                             <C>              <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .    $ 413            $ 464
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .      532              463
    Deferred Federal Income Taxes. . . . . . . . . . . . . .      106               34
    Deferred Investment Tax Credits. . . . . . . . . . . . .      (17)             (17)
    Amortization of Deferred Property Taxes. . . . . . . . .      138              135
    Cook Restart Expense Deferral. . . . . . . . . . . . . .      (90)             -
    Deferred Costs Under Fuel Clause Mechanisms. . . . . . .     (103)             (59)
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .      (99)            (174)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     (108)              14
    Accounts Payable . . . . . . . . . . . . . . . . . . . .       40              108
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .     (143)             (81)
    Interest Accrued . . . . . . . . . . . . . . . . . . . .       42               30
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . .      (43)              55
    Other Current Assets and Liabilities . . . . . . . . . .       42              124
  Payment of Disputed Tax and Interest Related to COLI . . .      (19)            (303)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .       57               52
        Net Cash Flows From Operating Activities . . . . . .      748              845

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .     (598)            (557)
  Other Investments. . . . . . . . . . . . . . . . . . . . .      (15)             (10)
  Proceeds from Sale of Property . . . . . . . . . . . . . .        5                9
        Net Cash Flows Used For Investing Activities . . . .     (608)            (558)

FINANCING ACTIVITIES:
  Issuance of Common Stock . . . . . . . . . . . . . . . . .       91               63
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .      545              618
  Retirement of Cumulative Preferred Stock . . . . . . . . .       (5)             -
  Retirement of Long-term Debt . . . . . . . . . . . . . . .     (416)            (548)
  Change in Short-term Debt (net). . . . . . . . . . . . . .       93              (20)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .     (347)            (343)
        Net Cash Flows Used For Financing Activities . . . .      (39)            (230)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .      101               57
Cash and Cash Equivalents at Beginning of Period . . . . . .      173               91
Cash and Cash Equivalents at End of Period . . . . . . . . .    $ 274            $ 148

Supplemental Disclosure:
  Cash paid for interest net of  capitalized amounts  was $344 million  and $279 million
  and for income taxes was $63 million  and $150 million in 1999 and 1998, respectively.
  Noncash  acquisitions  under  capital leases were $67 million and $94 million  in 1999
  and 1998, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)
<CAPTION>
                                           Three Months Ended       Nine Months Ended
                                              September 30,           September 30,
                                            1999        1998        1999        1998
                                                          (in millions)
<S>                                        <C>         <C>         <C>         <C>
BALANCE AT BEGINNING OF PERIOD . . . . .   $1,692      $1,645      $1,684      $1,605

NET INCOME . . . . . . . . . . . . . . .      174         195         413         464

DEDUCTIONS:
  Cash Dividends Declared. . . . . . . .      116         114         347         343

BALANCE AT END OF PERIOD . . . . . . . .   $1,750      $1,726      $1,750      $1,726


See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
  AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         SEPTEMBER 30, 1999
                           (UNAUDITED)

1. GENERAL

       The accompanying unaudited consolidated financial statements should
   be read in conjunction with the 1998 Annual Report as incorporated in
   and filed with the Form 10-K. Certain prior-period
   amounts have been reclassified to conform to current-period presentation.
   In the opinion of management, the
   financial statements reflect all normal recurring accruals and
   adjustments which are necessary for a fair presentation of the
   results of operations for interim periods.

2. FINANCING AND RELATED ACTIVITIES

       During the first nine months of 1999, subsidiaries issued
   $475 million of senior unsecured notes: $150 million at 6.60%
   due in 2009, $100 million at 6.75% due in 2004, $150 million
   at 6.875% due in 2004 and $75 million at 7% due in 2004.  Also
   $50 million of pollution control revenue bonds at 5.15% due in
   2026 were issued and short-term debt borrowings increased by
   $93 million.  In October 1999 an additional $50 million of
   senior unsecured notes at 7.45% due in 2004 were issued.

       Retirements of debt were: first mortgage bonds totaling
   $311 million with interest rates ranging from 6.55% to 8.43%
   and due dates ranging from 2003 to 2024, $50 million of
   pollution control revenue bonds at 7.40% due 2009 and $40
   million in term loans with interest rates ranging from 6.42%
   to 7.69% due in 1999.

3. NEW ACCOUNTING STANDARDS

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

4. RATE MATTERS

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

       On July 9, 1996, the AEP System companies filed an Open
   Access Transmission Tariff conforming with the FERC's pro-forma
   transmission tariff, subject to the resolution of certain
   pricing issues.  The 1996 tariff incorporated transmission
   rates which were the result of a settlement of a pending rate
   case, but which were being collected subject to refund from
   certain customers who opposed the settlement and continued to
   litigate the reasonableness of AEP's transmission rates.  On
   July 29, 1999, the FERC issued an order in the litigated rate
   case which would reduce AEP's rates for the affected customers
   below the settlement rate.  AEP and certain of the affected
   customers have sought rehearing of the Commission's Order.  The
   Company made a provision in September 1999 for the refund which
   it anticipates would result if the Commission's Order is upheld
   including interest.

5. INVESTMENT IN YORKSHIRE

       The Company has a 50% ownership interest in Yorkshire Power
   Group Limited (Yorkshire) which is accounted for using the
   equity method of accounting.  Equity income in Yorkshire is
   included in revenues from worldwide non-regulated operations.
   The following amounts which are not included in AEP's
   consolidated financial statements represent 100% of Yorkshire's
   summarized consolidated financial information:

                          Three Months Ended   Nine Months Ended
                            September 30,        September 30,
                           1999       1998      1999      1998
                                      (in millions)
   Income Statement Data:
    Operating Revenues   $523.0     $510.2   $1,679.7  $1,677.3
    Operating Income       48.5       82.6      200.5     264.8
    Net Income              8.3       21.5       38.5      13.6


<PAGE>
       In August 1999 the Office of Gas and Electricity Markets
   (OFGEM, which is the U.K. regulator of gas and electricity
   rates), published draft price proposals for the U.K.'s regional
   distribution businesses that would be effective for the five-year period
   beginning April 1, 2000.  Under the draft price
   proposals, the distribution rates for Yorkshire would be
   reduced 15% to 20% from current rates.  Yorkshire filed
   comments on September 17, 1999 with OFGEM expressing various
   concerns with the analysis used by OFGEM.  Yorkshire also
   commented that the methodology used failed to justify the
   magnitude of the price cuts proposed and suggested a more
   suitable methodology.

       On October 8, 1999, OFGEM issued updated draft price
   proposals for Yorkshire's electric distribution business. The
   updated proposal would require Yorkshire to reduce distribution
   rates 15% and transfer 8% of costs to Yorkshire's electricity
   supply business, an overall reduction in distribution prices
   of 23%.

       Also on October 8, 1999, OFGEM issued draft price proposals
   for Yorkshire's electric supply business.  Under the proposals,
   a supply price cap for certain domestic U.K. customers is
   retained from April 2000 through March 2002.  For Yorkshire,
   these proposals would result in a price reduction of
   approximately 10.7% on the standard domestic tariff commencing
   April 2000 and ending March 2001 and a nominal price freeze for
   the year commencing April 2001 and ending March 2002.

       OFGEM is expected to publish final proposals on both the
   distribution and the supply businesses at the end of November
   1999.  Yorkshire management intends to take all available
   opportunities to increase revenues and reduce costs to mitigate
   the impact of the final OFGEM distribution and supply price
   reductions.  Should Yorkshire be unable to  increase revenues
   and reduce costs in amounts sufficient to offset the impact of
   the OFGEM distribution and supply price reductions, AEP's
   equity earnings from its investment in Yorkshire will be
   significantly reduced in comparison to its current level of
   earnings.

6. BUSINESS SEGMENTS

       The Company's principal business segment is its cost based
   rate regulated Domestic Electric Utility business consisting
   of seven regulated utility operating companies providing
   residential, commercial, industrial and wholesale electric
   services in seven Atlantic and Midwestern states.  Also
   included in this segment are the Company's electric power
   wholesale marketing and trading activities that are conducted
   as part of regulated operations and subject to cost of service
   rate regulation.  Worldwide Non-regulated Electric and Gas
   Operations are comprised of a Worldwide Energy Investments
   segment and other business segments.  The Worldwide Energy
   Investments segment represents principally international
   investments in energy-related projects and operations.  It also
   includes the development and management of such projects and
   operations.  Such investment activities include electric
   generation, supply and distribution, and natural gas pipeline,
   storage and other natural gas services.  Other business
   segments include non-regulated electric and gas trading
   activities, telecommunication services,  and  the  marketing
   of  various  energy   saving products and services.  Financial
   data for the business segments for the nine months ending
   September 30, 1999 and 1998 is shown in the following table:
<TABLE>
<CAPTION>
                                                   Worldwide Non-regulated
                                                 Electric and Gas Operations
                                 Regulated
                                 Domestic    World
                                 Electric    Wide Energy              Reconciling    AEP
                                 Utilities   Investments    Other     Adjustments    Consolidated
                                                         (in millions)
 <S>                           <C>           <C>            <C>          <C>          <C>
 September 30, 1999
   Revenues from
     external customers     $ 4,809       $  553         $ 79         $(190)       $ 5,251
   Revenues from
     transactions with other
     operating segments        -              47          143          (190)          -
   Segment net income (loss)    409           20          (16)          -              413
   Total assets              17,375        2,333          730           -           20,438
 September 30, 1998
   Revenues from
     external customers       4,916           20           -            -            4,936
   Revenues from
     transactions with other
     operating segments        -             -             -            -             -
   Segment net income (loss)    485          (12)          (9)          -              464
   Total assets              16,723          472          281           -           17,476
</TABLE>
7. MERGER

       As discussed in Note 5 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the Company and
   Central and South West Corporation (CSW) announced plans to
   merge in December 1997.  In 1998 the appropriate shareholder
   proposals for the consummation of the merger were approved.
   Approval of the merger has been requested from the FERC, the
   Securities and Exchange Commission (SEC), the Nuclear
   Regulatory Commission (NRC) and all of CSW's state regulatory
   commissions: Arkansas, Louisiana, Oklahoma and Texas.  On July
   29, 1999 applications were made with the Federal Communication
   Commission to authorize the transfer of control of licenses of
   several CSW entities to the Company.  AEP and CSW made a merger
   filing with the Department of Justice in July 1999.  The NRC
   and the Arkansas Public Service Commission approved the merger
   in 1998.  In 1998 the FERC issued an order which confirmed that
   a 250 megawatt firm contract path with the Ameren System was
   available.  The contract path was obtained by  the Company and
   CSW to meet the requirement of the Public Utility Holding
   Company Act of 1935 that the two systems operate on an
   integrated and coordinated basis.


<PAGE>
   FERC

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

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

   Louisiana

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

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

   Oklahoma

       On May 11, 1999, the Oklahoma Corporation Commission (OCC)
   approved the proposed merger between the Company and CSW.  The
   approval follows an administrative law judge's oral decision
   on a partial settlement between certain principal parties to
   the Oklahoma merger proceeding which recommended that the OCC
   approve the merger.  The partial settlement provides for
   sharing of net merger savings with Oklahoma customers; no
   increase in Oklahoma base rates prior to January 1, 2003;
   filing by December 31, 2001 with the FERC an application to
   join a regional transmission organization; and implementing
   additional quality of service standards for Oklahoma retail
   customers.  Oklahoma's share (approximately $50 million) of net
   merger savings over the first five years after the merger is
   consummated will be shared between Oklahoma customers and AEP
   shareholders.  The partial settlement agreement includes a
   recommendation by the OCC staff that the OCC file with FERC
   indicating that it does not oppose the merger, but reserves the
   right to ensure that there are no adverse impacts on the
   Oklahoma transmission system.  Certain municipal and
   cooperative customers have appealed the OCC's merger approval
   order.  On October 13, 1999 this appeal was dismissed by the
   Oklahoma Supreme Court and the cooperative customers have since
   asked the OCC to dismiss their appeal.

   Texas

       On May 4, 1999, AEP and CSW announced that a stipulated
   settlement had been reached in Texas.  The agreement builds
   upon an earlier settlement agreement signed by AEP, CSW and
   certain parties to the Texas merger proceeding.  In addition
   to the parties that were signatories to the earlier agreement,
   the staff of the Public Utility Commission of Texas is a
   signatory to the new settlement as well as other key parties
   to the merger proceeding.  The stipulated settlement would
   result in rate reductions totaling $221 million over a six-year
   period for Texas customers after the merger is completed.  The
   $221 million rate reduction is composed of $84.4 million of net
   merger savings and $136.6 million to resolve existing issues
   associated with CSW operating subsidiaries' rate and fuel
   reconciliation proceedings in Texas.  Under the terms of the
   settlement agreement, base rates would not be increased before
   January 1, 2003 or three years after the merger, whichever is
   later.  The settlement also calls for the divestiture of a
   total of 1,604 megawatts of existing and proposed generating
   capacity within Texas.  If it is determined that the
   divestiture can proceed immediately after the merger closes
   without jeopardizing pooling-of-interests accounting treatment
   for the merger, sale of the plants would begin no later than
   90 days after the merger closes.  Absent that determination,
   the divestiture would occur approximately two years after the
   merger closes to satisfy the requirements to use pooling-of-interests
   accounting treatment.  Other provisions in the
   settlement agreement provide for, among other things,
   accelerated stranded cost recovery, quality-of-service
   standards, continuation of programs for disadvantaged customers
   and transfer of control of bulk transmission facilities to a
   regional transmission organization.  Hearings on the merger in
   Texas began August 9, 1999 and concluded on August 10, 1999.
   As the hearings began, settlements were reached with all but
   one of the parties in the case.  The settling parties are all
   wholesale electric customers of CSW's Texas electric operating
   companies.  The settlements call for the withdrawal of their
   opposition to the merger in all regulatory approval
   proceedings.  On November 4, 1999 the Texas Commission, in its
   open meeting approved the application on the pending merger and
   the stipulated settlement announced in May.

   Indiana

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

   Kentucky

       On April 15, 1999, in compliance with a request from the
   staff of the Kentucky Public Service Commission (KPSC) AEP
   filed an application seeking KPSC approval for the indirect
   change in control of Kentucky Power Company that will occur as
   a result of the proposed merger.  Although AEP did not believe
   that the KPSC has the jurisdictional authority to approve the
   merger, AEP reached a merger settlement agreement on May 24,
   1999 with key parties in Kentucky which the KPSC approved on
   June 14, 1999.  Under the terms of the Kentucky settlement, AEP
   has agreed to share net merger savings with Kentucky customers;
   establish performance standards that will maintain or improve
   customer service and system reliability; and to establish rules
   to protect consumers and promote fair competition.  The
   Kentucky customers' share of the net merger savings are
   expected to be approximately $28 million.  The key parties to
   the Kentucky settlement agreed not to oppose the merger during
   the FERC or the SEC proceedings.

   Ohio

       On October 21, 1999, the Public Utilities Commission of
   Ohio (PUCO) issued a decision stating that it will notify the
   FERC that it will withdraw its opposition to the Company's
   pending merger with CSW and will not seek conditions on the
   merger.

       American Municipal Power - Ohio (AMP-Ohio) and AEP reached
   a settlement addressing outstanding issues.  As part of the
   settlement AMP-Ohio agreed to withdraw as an intervenor in the
   merger process.  AMP-Ohio is the nonprofit wholesale power
   supplier and service provider for most of Ohio's 84 community-owned
   public power systems, two West Virginia public power
   systems and four Pennsylvania public power systems.

   Other

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

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

   Completion of the Merger

       As of September 30, 1999, AEP had deferred $37 million of
   costs related to the merger on its consolidated balance sheet,
   which will be charged to expense if AEP and CSW are not
   successful in completing their proposed merger.  If the merger
   is consummated the deferred costs allocable to the regulated
   electric operating subsidiaries will be amortized over their
   recovery period, generally 5-years, in accordance with state
   regulator orders.  The remainder of the deferred merger costs
   will be expensed upon consummation of the merger.

       The merger is conditioned upon, among other things, the
   approval of certain state and federal regulatory agencies.  The
   transaction must satisfy many conditions, a number of which may
   not be waived by the parties, including the condition that the
   merger must be accounted for as a pooling of interests.  The
   merger agreement will terminate on December 31, 1999 unless
   extended for six months by either party as provided in the
   merger agreement.  Although consummation of the merger is
   expected to occur in the second quarter of 2000, the Company
   is unable to predict the outcome or the timing of the required
   regulatory proceedings.

8. RESTRUCTURING LEGISLATION

   Virginia

       In March 1999 a law was enacted in Virginia to restructure
   the electric utility industry.  Under the restructuring law a
   transition to choice of electricity supplier for retail
   customers will commence on January 1, 2002 and be completed,
   subject to a finding by the Virginia State Corporation
   Commission (Virginia SCC) that an effective competitive market
   exists, on January 1, 2004.

       The law also provides an opportunity for recovery of just
   and reasonable net stranded generation costs.  Stranded costs
   are those costs above market including generation related
   regulatory assets and impaired tangible assets that potentially
   would not be recoverable in a competitive market.  The
   mechanisms in the Virginia law for stranded cost recovery are:
   a capping of rates until as late as July 1, 2007, and the
   application of a wires charge upon customers who depart the
   incumbent utility in favor of an alternative supplier prior to
   the termination of the rate cap.  The law provides for the
   establishment of capped rates prior to January 1, 2001 and the
   establishment of a wires charge by the fourth quarter of 2001.

       Management has concluded that as of September 30, 1999 the
   requirements to apply Statement of Financial Accounting
   Standards (SFAS) 71, "Accounting for the Effects of Certain
   Types of Regulation," continue to be met.  The Company's
   Virginia rates for generation will continue to be cost-based
   regulated until the establishment of capped rates and the wires
   charge as provided in the law.  The establishment of capped
   rates and the wires charge should enable the Company to
   determine its ability to recover stranded costs, a requirement
   to discontinue application of SFAS 71.

       When the capped rates and the wires charge are established
   in Virginia, the application of SFAS 71 will be discontinued
   for the Virginia retail jurisdiction portion of the Company's
   generating business.  At that time the Company will have to
   write-off its generation-related regulatory assets to the
   extent that they cannot be recovered under capped rates and
   wire charges approved by the Virginia SCC under the provisions
   of the restructuring law and record any asset impairments in
   accordance with SFAS 121, "Accounting for the Impairment of
   Long-lived Assets and for Long-lived Assets to Be Disposed Of."
   An impairment loss would be recorded to the extent that the
   cost of impaired assets cannot be recovered through the
   transition recovery mechanisms provided by the law and future
   market prices.  Absent the determination in the regulatory
   process of capped rates, wires charges and other pertinent
   information, it is not possible at this time to determine if
   any generation related assets are impaired in accordance with
   SFAS 121 and if generation related regulatory assets will be
   recovered.  The amount of regulatory assets recorded on the
   books applicable to the Company's Virginia retail generating
   business at September 30, 1999 is estimated to be $60 million
   before related tax effects.

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

   Ohio

       The Ohio Electric Restructuring Act of 1999 became law on
   October 4, 1999.  The law provides for customer choice of
   electricity supplier, a residential rate reduction of 5% and
   a freezing of the unbundled generation base rates and a
   freezing of fuel rates beginning on January 1, 2001.  The law
   also provides for a five-year transition period to transition
   from cost based rates to market pricing for generation
   services.  It authorizes the PUCO to address certain major
   transition issues including unbundling of rates and the
   recovery of regulatory assets including any unrecovered
   deferred fuel costs, stranded plant and mining costs and other
   transition costs.

       Retail electric services that will be competitive are
   defined in the law as electric generation service, aggregation
   service, and power marketing and brokering.  Under the
   legislation the PUCO is granted broad oversight responsibility
   and is required by the law to promulgate rules for competitive
   retail electric generation service.  The law also gives the
   PUCO authority to approve a transition plan for each electric
   utility company.

       The law provides Ohio electric utilities with an
   opportunity to recover PUCO approved allowable transition costs
   through unbundled frozen generation rates paid through December
   31, 2005 by customers who do not switch generation suppliers
   and through a wires charge for customers who switch generation
   suppliers.  Transition costs can include regulatory assets,
   impairments of generating assets and other stranded costs,
   employee severance and retraining costs, consumer education
   costs and other costs.  Recovery of transition costs can, under
   certain circumstances, extend beyond the five-year frozen rate
   transition period but cannot continue beyond December 31, 2010.
   The Company must file a transition plan with the PUCO by
   January 3, 2000 and the PUCO is required to issue a transition
   order no later than October 31, 2000.

       The law also provides that the property tax assessment
   percentage on electric generation property be lowered from 100%
   to 25% of value effective January 1, 2001.  Electric utilities
   will become subject to the Ohio Corporate Franchise Tax and
   municipal income taxes on January 1, 2002.  The last year for
   which electric utilities will pay the excise tax based on gross
   receipts is the tax year ending April 30, 2002.  As of May 1,
   2001 electric distribution companies will be subject to an
   excise tax based on kilowatt-hours sold to Ohio customers.  The
   gross receipts tax is paid at the beginning of the tax year,
   deferred as a prepaid expense and amortized to expense during
   the tax year pursuant to the tax laws whereby the payment of
   the tax results in the privilege to conduct business in the
   year following the payment of the tax.  The change in the tax
   law to impose an excise tax based on kilowatt-hours sold to
   Ohio customers commencing before the expiration of the gross
   receipts tax privilege period will result in a 12 month period
   when electric utilities are recording as an expense both the
   gross receipts tax and the excise tax.  Management intends to
   seek recovery of the overlap of the gross receipts and excise
   taxes in the Ohio transition plan filing.

       As discussed in Note 3, "Effects of Regulation and Phase-In
   Plans," of the Notes to Consolidated Financial Statements in
   the 1998 Annual Report, the Company defers as regulatory assets
   and liabilities certain expenses and revenues consistent with
   the regulatory process in accordance with SFAS 71.  Management
   has concluded that as of September 30, 1999 the requirements
   to apply SFAS 71 continue to be met since the Company's rates
   for generation will continue to be cost-based regulated until
   the establishment of unbundled frozen generation rates and a
   wires charge as provided in the law.  The establishment of
   unbundled frozen generation rates and the wires charge should
   enable the Company to determine its ability to recover
   transition costs including regulatory assets and other stranded
   costs, a requirement to discontinue application of SFAS 71.

       When unbundled generation rates and the wires charge are
   established, the application of SFAS 71 will be discontinued
   for the Ohio retail jurisdiction portion of the  generation
   business.  At that time the Company will have to write-off its
   Ohio jurisdictional generation-related regulatory assets to the
   extent that they cannot be recovered under the unbundled frozen
   generation rates and distribution wires charges approved by the
   PUCO under the provisions of the restructuring law and record
   any asset impairments in accordance with SFAS 121.  An
   impairment loss would be recorded to the extent that the cost
   of generation assets cannot be recovered through the transition
   recovery mechanisms provided by the law and future market
   prices.  Absent the determination in the regulatory process of
   an unbundled frozen generation rate, the wires charge and other
   pertinent information, it is not possible at this time to
   determine if any of the Company's generating assets are
   impaired in accordance with SFAS 121.  The amount of regulatory
   assets recorded on the books at September 30, 1999 applicable
   to the Ohio retail jurisdictional generating business is $638
   million before related tax effects.  Due to the planned closing
   of affiliated mines including the Meigs mine, and other
   anticipated events, generation-related regulatory assets as of
   December 31, 2000 allocable to the Ohio retail jurisdiction are
   estimated to exceed $800 million, before federal income tax
   effects.  Recovery of these regulatory assets will be sought
   as a part of the Company's Ohio transition plan filing.

       An estimated determination of whether the Company will
   experience any asset impairment loss regarding its Ohio retail
   jurisdictional generating assets and any loss from a possible
   inability to recover Ohio generation related regulatory assets
   and other transition costs cannot be made until such time as
   the unbundled frozen generation rates and the wires charge are
   determined through the regulatory process.  Management will
   seek full recovery of generation-related regulatory assets, any
   stranded costs and other transition costs in its transition
   plan filing.  The PUCO is required to complete its regulatory
   process and issue a transition order establishing the
   transition rates and wires charges by no later than October 31,
   2000.  Should the PUCO fail to approve transition rates and
   wires charges that are sufficient to recover the Company's
   generation-related regulatory assets, any other stranded costs
   and transition costs, it could have a material adverse effect
   on results of operations, cash flows and financial condition.

9. CONTINGENCIES

   Litigation

       As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the
   deductibility of certain interest deductions related to AEP's
   corporate owned life insurance (COLI) program for taxable years
   1991-1996 is under review by the Internal Revenue Service
   (IRS).  Adjustments have been or will be proposed by the IRS
   disallowing COLI interest deductions.  A disallowance of COLI
   interest deductions through September 30, 1999 would reduce
   earnings by approximately $317 million (including interest).
   The Company has made no provision for any possible earnings
   impact from this matter.

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

       In order to resolve this issue, the Company filed suit
   against the United States (US) in the US District Court for the
   Southern District of Ohio in March 1998.  A US Tax Court judge
   recently decided in the Winn-Dixie Stores v. Commissioner case
   that a corporate taxpayer's COLI interest deductions should be
   disallowed.  Notwithstanding the decision in Winn-Dixie,
   management believes, and has been advised by outside counsel,
   that it has a meritorious position and will vigorously pursue
   its lawsuit.  In the event the resolution of this matter is
   unfavorable, it will have a material adverse impact on results
   of operations and cash flows.

   Air Quality

       As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the U.S.
   Environmental Protection Agency (Federal EPA) issued final
   rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which
   the Company's generating plants are located.  A number of
   utilities, including the Company, filed petitions seeking a
   review of the final rules in the U.S. Court of Appeals for the
   District of Columbia Circuit (Appeals Court).  The matter is
   currently being litigated.

       On April 30, 1999, Federal EPA took final action with
   respect to petitions filed by eight northeastern states
   pursuant to Section 126 of the Clean Air Act.  Federal EPA
   approved portions of the states' petitions that would impose
   NOx reduction requirements on AEP System generating units which
   are approximately equivalent to the reductions contemplated by
   the NOx emission reduction final rules.  The AEP System
   companies with generating plants, as well as other utility
   companies, filed a petition in the Appeals Court seeking review
   of Federal EPA's approval of portions of the northeastern
   states' petitions.  In the second quarter of 1999, three
   additional northeastern states filed Section 126 petitions with
   Federal EPA similar to those originally filed by the eight
   northeastern states.

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

   Federal EPA Complaint and Notice of Violation

       On November 3, 1999 the Department of Justice, at the
   request of Federal EPA, filed a complaint in the U.S. District
   Court for the Southern District of Ohio that alleges the
   Company made modifications to generating units at its Muskingum
   River, Mitchell, Philip Sporn, Tanners Creek and Cardinal
   plants over the course of the past 25 years to extend unit
   operating lives or to increase unit generating capacity without
   a preconstruction permit in violation of the Clean Air Act.
   Federal EPA also issued a Notice of Violation to the Company
   alleging violations of the New Source Review and New Source
   Performance Standard provisions of the Clean Air Act at these
   same plants as well as Conesville Plant.  A number of
   unaffiliated utilities also received Notices of Violation,
   complaints or administrative orders including a Notice of
   Violation issued to The Cincinnati Gas & Electric Company for
   Beckjord Plant alleging violations of the New Source Review
   provisions of the Clean Air Act.  Columbus Southern Power
   Company owns a partial interest in Unit 6 of Beckjord Plant.

       Federal EPA's Notice of Violation and the government's
   complaint are based on an investigation by Federal EPA to
   assess compliance with the New Source Review and New Source
   Performance Standard provisions of the Clean Air Act.  Under
   these provisions of the Clean Air Act, if a plant undertakes
   a major modification that directly results in an emissions
   increase, permitting requirements under the New Source Review
   program might be triggered and the plant may be required to
   install additional pollution control technology.  This
   requirement does not apply to activities such as routine
   maintenance, replacement of degraded equipment or failed
   components, or other repairs needed for the reliable, safe and
   efficient operation of the plant.

       In the fall of 1999 the State of New York, various
   environmental groups and the State of Connecticut each
   separately threatened to sue the Company under the Clean Air
   Act to compel compliance with the New Source Review and New
   Source Performance Standard provisions, alleging that
   modifications occurred at certain units at the Company's Philip
   Sporn Plant, Kammer Plant, Mitchell Plant, Muskingum River
   Plant, Gavin Plant, Cardinal Plant, Clinch River Plant, Kanawha
   River Plant, Tanners Creek Plant, Amos Plant and Big Sandy
   Plant.  The State of New York also threatened to sue five
   unaffiliated utilities.  In addition, the State of New York
   indicated that it may seek to recover, under state law,
   compensation for alleged environmental damage caused by excess
   emissions of sulfur dioxide and nitrogen oxides.

       Management believes its maintenance, repair and replacement
   activities were in conformity with the Clean Air Act and were
   exempted from the New Source Review and New Source Performance
   Standard requirements, and intends to vigorously pursue its
   defense of this matter.

       The Clean Air Act authorizes civil penalties of up to
   $27,500 per day per violation at each generating unit ($25,000
   per day prior to January 30, 1997).  Civil penalties, if
   ultimately imposed by the court, and the cost of any required
   new pollution control equipment, if the court accepts all of
   Federal EPA's contentions, could be  substantial.

       In the event the Company does not prevail, any capital and
   operating costs of additional pollution control equipment that
   may be required as well as any penalties imposed would
   adversely affect future results of operations, cash flows and
   possibly financial condition unless such costs can be recovered
   through regulated rates, and where states are deregulating
   generation, approved unbundled transition generation rates,
   wires charges and future market prices for energy.

   Cook Nuclear Plant Shutdown

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

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

       The Company's plan to restart the Cook Plant units has Unit
   2 scheduled to return to service in April 2000 and Unit 1 to
   return to service in September 2000.  The restart plan was
   developed based upon a comprehensive systems readiness review
   of all operating systems at the Cook Plant.  When maintenance
   and other activities required for restart are complete, the
   Company will seek concurrence from the NRC to return the Cook
   Plant to service.

       Management intends to replace the steam generator for Unit
   1 before the unit is returned to service.  Costs associated
   with the steam generator replacement are estimated to be
   approximately $165 million, which will be accounted for as a
   capital investment unrelated to the restart.  At September 30,
   1999, $82 million has been spent on the steam generator
   replacement.

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

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

       In June 1999 the Company announced that a settlement
   agreement for two open Michigan power supply cost recovery
   reconciliation cases had been reached with the staff of the
   Michigan Public Service Commission (MPSC).  The proposed
   settlement agreement would limit the Company's ability to
   increase base rates and freeze power supply costs for five
   years, allow for the amortization of deferred power supply cost
   for 1997, 1998 and 1999 over five years, allow for the deferral
   and amortization of non-fuel nuclear operation and maintenance
   expenses over five years and resolve all issues related to the
   Cook Plant extended restart outage. The pending Michigan
   settlement limits deferrals to $50 million of 1999
   jurisdictional non-fuel nuclear operation and maintenance
   costs. Hearings have been held to give the one intervenor who
   opposed the approval of the settlement agreement the
   opportunity to voice its objections.  The settlement agreement
   is pending before the MPSC.

       Expenditures for the restart of the Cook units are
   estimated to total approximately $574 million and will be
   accounted for primarily as a current period operation and
   maintenance expense in 1999 and 2000.  Through September 30,
   1999, $280 million has been spent, of which $196 million was
   incurred in 1999.  Pursuant to the Indiana settlement agreement
   $112.5 million of incremental operation and maintenance costs
   were deferred for the nine months ended September 30, 1999.
   The Indiana jurisdiction deferral is limited to up to $150
   million of incremental restart costs incurred in 1999.  The
   amortization of such costs through September 30, 1999 was $22.5
   million.  At September 30, 1999, the unamortized balance of
   incremental restart related operation and maintenance costs was
   $90 million and was included in regulatory assets.  Also
   deferred as a regulatory asset at September 30, 1999 was $148
   million of replacement energy fuel costs.

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

   Other

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

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

            THIRD QUARTER 1999 vs. THIRD QUARTER 1998
                               AND
             YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
   Net income decreased by $21 million or 11% for the quarter and
$51 million or 11% for the year-to-date period due predominantly to
a decrease in wholesale energy sales and margins, an increase in
costs to prepare the Cook Plant for restart following an extended
outage in the Company's domestic regulated electric utility
operations and an increase in interest expense to finance
acquisitions in the Company's worldwide non-regulated operations.
   Income statement line items which changed significantly were:
                                     Increase (Decrease)
                              Third Quarter       Year-to-Date
                           (in millions)   %   (in millions)   %

Revenues:
  Domestic Regulated
   Electric Utilities. . .     $(88)       (5)     $(107)     (2)
  Worldwide Non-regulated
   Operations. . . . . . .      144       N.M.       422     N.M.
Fuel and Purchased
   Power Expense . . . . .      (21)       (3)       (75)     (4)
Maintenance and Other
 Operation Expense . . . .       (5)       (1)        43       3
Worldwide Non-regulated
 Operations Expense. . . .      113       N.M.       332     N.M.
Interest and Preferred
 Dividends . . . . . . . .       26        24         78      24
Income Taxes . . . . . . .      (36)      (34)       (42)    (16)

N.M. = Not Meaningful

   Revenues from domestic regulated electric utility operations
decreased in both the third quarter and the year-to-date periods
due predominantly to decreased energy sales to wholesale customers
and a decline in margins on wholesale energy sales.  Energy sales
to wholesale customers declined 16% in the quarter and 20% in the
year-to-date period primarily due to weather and its effect on
energy demand.  Margins on trading in AEP's marketing area declined
$100 million in the quarter and $90 million for the year-to-date
period reflecting the effect of milder summer weather.
   The increase in revenues from worldwide non-regulated
operations was predominantly due to the acquisition in December
1998 of CitiPower, an Australian electric distribution utility, and
Louisiana Intrastate Gas, a midstream natural gas operation in
Louisiana.
   The decreases in fuel and purchased power expense were
primarily attributable to a decrease in coal-fired generation
reflecting the decline in demand for electricity and an increase in
the deferral of the non-fuel components of the fuel clauses for
recovery in later periods in the domestic regulated electric
utility operations.  In the year-to-date period, a decline in
purchased power as a result of the reduced wholesale demand also
contributed to the decrease.
   Maintenance and other operation expense increased for the year-to-date
period largely as a result of expenditures to prepare the
Cook Plant units for restart following an extended Nuclear
Regulatory Commission (NRC) monitored outage which began in
September 1997.
   Worldwide non-regulated expenses increased as a result of the
expansion of business development activities and expenses of
CitiPower and Louisiana Intrastate Gas which were acquired in
December 1998.
   Additional borrowings to fund the Company's non-regulated
operations, primarily the acquisitions of CitiPower and Louisiana
Intrastate Gas in December 1998, were the primary reason for the
significant increase in interest and preferred dividends.
   The decrease in income taxes is primarily attributable to a
decrease in United States federal income taxes which was due to a
decrease in pre-tax income and adjustments to prior years tax
returns.
FINANCIAL CONDITION
   Total plant and property additions including capital leases for
the first nine months of 1999 were $665 million.

<PAGE>
   During the first nine months of 1999, subsidiaries issued $550
million principal amount of long-term obligations at interest rates
ranging from 5.15% to 10.53%; retired $401 million principal amount
of long-term debt with interest rates ranging from 6.42% to 8.43%;
and increased short-term debt by $93 million.
OTHER MATTERS
Spent Nuclear Fuel (SNF) Litigation
   As discussed in Management's Discussion and Analysis of Results
of Operations and Financial Condition (MDA) in the 1998 Annual
Report, as a result of the Department of Energy's (DOE) failure to
make sufficient progress toward a permanent repository or otherwise
assume responsibility for SNF, the Company along with a number of
unaffiliated utilities and states filed suit in the United States
(US) Court of Appeals for the District of Columbia Circuit
requesting, among other things, that the court order DOE to meet
its obligations under the law.  The court ordered the parties to
proceed with contractual remedies but declined to order DOE to
begin accepting SNF for disposal.  DOE estimates its planned site
for the nuclear waste will not be ready until at least 2010.  In
June 1998, the Company filed a complaint in the US Court of Federal
Claims seeking damages in excess of $150 million due to the DOE's
partial material breach of its unconditional contractual deadline
to begin disposing of SNF generated by the Cook Plant.  Similar
lawsuits have been filed by other utilities.  On April 6, 1999, the
court granted DOE's motion to dismiss a lawsuit filed by another
utility.  On May 20, 1999, the other utility appealed this decision
to the U.S. Court of Appeals for the Federal Circuit.  I&M's case
has been stayed pending final resolution of the other utility's
appeal.
United Kingdom Price Reduction Proposal
   In August 1999 the Office of Gas and Electricity Markets
(OFGEM, which is the U.K. regulator of gas and electricity rates),
published draft price proposals for the U.K.'s regional
distribution businesses that would be effective for the five-year
period beginning April 1, 2000.  Under the draft price proposals,
the distribution rates for Yorkshire would be reduced 15% to 20%
from current rates.  Yorkshire filed comments on September 17, 1999
with OFGEM expressing various concerns with the analysis used by
OFGEM.  Yorkshire also commented that the methodology used failed
to justify the magnitude of the price cuts proposed and suggested
a more suitable methodology.
   On October 8, 1999, OFGEM issued updated draft price proposals
for Yorkshire's electric distribution business. The updated
proposal would require Yorkshire to reduce distribution rates 15%
and transfer 8% of costs to Yorkshire's electricity supply
business, an overall reduction in distribution prices of 23%.
   Also on October 8, 1999, OFGEM issued draft price proposals for
Yorkshire's electric supply business.  Under the proposals, a
supply price cap for certain domestic U.K. customers is retained
from April 2000 through March 2002.  For Yorkshire, these proposals
would result in a price reduction of approximately 10.7% on the
standard domestic tariff commencing April 2000 and ending March
2001 and a nominal price freeze for the year commencing April 2001
and ending March 2002.
   OFGEM is expected to publish final proposals on both the
distribution and the supply businesses at the end of November 1999.
Yorkshire management intends to take all available opportunities to
increase revenues and reduce costs to mitigate the impact of the
final OFGEM distribution and supply price reductions.  Should
Yorkshire be unable to increase revenues and reduce costs in
amounts sufficient to offset the impact of the OFGEM distribution
and supply price reductions, AEP's equity earnings from its
investment in Yorkshire will be significantly reduced in comparison
to its current level of earnings.
Merger
   As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the Company and Central and
South West Corporation (CSW) announced plans to merge in December
1997.  In 1998 the appropriate shareholder proposals for the
consummation of the merger were approved.  Approval of the merger
has been requested from the Federal Energy Regulatory Commission
(FERC), the Securities and Exchange Commission (SEC), the Nuclear
Regulatory Commission (NRC) and all of CSW's state regulatory
commissions: Arkansas, Louisiana, Oklahoma and Texas.  On July 29,
1999 applications were made with the Federal Communication
Commission to authorize the transfer of control of licenses of
several CSW entities to the Company.  AEP and CSW made a merger
filing with the Department of Justice in July 1999.  The NRC and
the Arkansas Public Service Commission approved the merger in 1998.
In 1998 the FERC issued an order which confirmed that a 250
megawatt firm contract path with the Ameren System was available.
The contract path was obtained by  the Company and CSW to meet the
requirement of the Public Utility Holding Company Act of 1935 that
the two systems operate on an integrated and coordinated basis.
FERC
   In November, 1998 the FERC issued an order establishing hearing
procedures for the merger.  The 1998 FERC order indicated that the
review of the proposed merger will address the issues of
competition, market power and customer protection.  On May 25, 1999
AEP and CSW reached a settlement with the FERC trial staff
resolving competition and rate issues relating to the merger.  On
July 13, 1999 AEP and CSW reached an additional settlement with the
FERC trial staff resolving additional issues.  The settlements were
submitted to the FERC for approval.  Under the terms of the
settlements, AEP filed with the FERC a regional transmission
organization (RTO) proposal whereby it will transfer the operation
and control of AEP's bulk transmission facilities to an RTO.  The
settlements also cover rates for transmission services and
ancillary service as well as resolving issues related to system
integration agreements and confirm, subject to FERC guidance on
certain elements, that the proposed generation divestiture of up to
550 megawatts of capacity will satisfy the staff's market power
concerns.  The hearings began on June 29, 1999 and concluded on
July 19, 1999.
   On June 28, 1999, the Company and CSW filed a motion asking the
FERC to waive the requirement for a post-hearing decision by an
administrative law judge (ALJ) who presides over the merger
hearing.  The motion indicated that the commission could then
decide the matter based on the hearing record and briefs submitted
by all interested parties.  On July 28, 1999, the FERC ordered the
ALJ to issue an initial decision as soon as possible, but no later
than November 24, 1999.  The commission concluded that it needed
the benefit of the ALJ's opinion and, therefore, decided not to
grant the request.  The procedural schedule that follows the ALJ's
initial decision should allow the FERC to issue a final order in
the first quarter of 2000.
Louisiana
   On July 29, 1999 the Louisiana Public Service Commission (LPSC)
approved the merger between the Company and CSW subject to final
FERC approval.  In granting approval, the LPSC also approved a
stipulated settlement in which the Company and CSW agreed to share
with SWEPCO's Louisiana customers merger savings created as a
result of the merger over the eight years following its
consummation.  The merger savings are estimated to total more than
$18 million during that eight-year period.  In addition the
settlement also includes:
       A cap on base rates for five years after consummation of
       the merger;
       Sharing of benefits from off-system sales;
       Establishment of conditions for affiliate transactions
       with other AEP and CSW subsidiaries;
       Provisions to ensure continued quality of service; and
       Provisions to hold SWEPCO's Louisiana customers harmless
       for adverse effects of the merger, if any.
Oklahoma
   On May 11, 1999, the Oklahoma Corporation Commission (OCC)
approved the proposed merger between the Company and CSW.  The
approval follows an administrative law judge's oral decision on a
partial settlement between certain principal parties to the
Oklahoma merger proceeding which recommended that the OCC approve
the merger.  The partial settlement provides for sharing of net
merger savings with Oklahoma customers; no increase in Oklahoma
base rates prior to January 1, 2003; filing by December 31, 2001
with the FERC an application to join a regional transmission
organization; and implementing additional quality of service
standards for Oklahoma retail customers.  Oklahoma's share
(approximately $50 million) of net merger savings over the first
five years after the merger is consummated will be shared between
Oklahoma customers and AEP shareholders.  The partial settlement
agreement includes a recommendation by the OCC staff that the OCC
file with FERC indicating that it does not oppose the merger, but
reserves the right to ensure that there are no adverse impacts on
the Oklahoma transmission system.  Certain municipal and
cooperative customers have appealed the OCC's merger approval
order.  On October 13, 1999 this appeal was dismissed by the
Oklahoma Supreme Court and the cooperative customers have since
asked the OCC to dismiss their appeal.
Texas
   On May 4, 1999, AEP and CSW announced that a stipulated
settlement had been reached in Texas.  The agreement builds upon an
earlier settlement agreement signed by AEP, CSW and certain parties
to the Texas merger proceeding.  In addition to the parties that
were signatories to the earlier agreement, the staff of the Public
Utility Commission of Texas is a signatory to the new settlement as
well as other key parties to the merger proceeding.  The stipulated
settlement would result in rate reductions totaling $221 million
over a six-year period for Texas customers after the merger is
completed.  The $221 million rate reduction is composed of $84.4
million of net merger savings and $136.6 million to resolve
existing issues associated with CSW operating subsidiaries' rate
and fuel reconciliation proceedings in Texas.  Under the terms of
the settlement agreement, base rates would not be increased before
January 1, 2003 or three years after the merger, whichever is
later.  The settlement also calls for the divestiture of a total of
1,604 megawatts of existing and proposed generating capacity within
Texas.  If it is determined that the divestiture can proceed
immediately after the merger closes without jeopardizing
pooling-of-interests accounting treatment for the merger, sale of the
plants would begin no later than 90 days after the merger closes.
Absent that determination, the divestiture would occur
approximately two years after the merger closes to satisfy the
requirements to use pooling-of-interests accounting treatment.
Other provisions in the settlement agreement provide for, among
other things, accelerated stranded cost recovery, quality-of-service
standards, continuation of programs for disadvantaged
customers and transfer of control of bulk transmission facilities
to a regional transmission organization.  Hearings on the merger in
Texas began August 9, 1999 and concluded on August 10, 1999.  As
the hearings began, settlements were reached with all but one of
the parties in the case.  The settling parties are all wholesale
electric customers of CSW's Texas electric operating companies.
The settlements call for the withdrawal of their opposition to the
merger in all regulatory approval proceedings.  On November 4, 1999
the Texas Commission, in its open meeting approved the application
on the pending merger and the stipulated settlement announced in
May.
Indiana
   The Indiana Utility Regulatory Commission (IURC) approved a
settlement agreement related to the merger on April 26, 1999.  The
settlement agreement resulted from an investigation of the proposed
merger initiated by the IURC.  The terms of the settlement
agreement provide for, among other things, a sharing of net merger
savings through reductions in customers' bills of approximately $67
million over eight years after the merger is completed; a one year
extension through January 1, 2005 of a freeze in base rates;
additional annual deposits of $5.5 million to the nuclear
decommissioning trust fund for the Indiana jurisdiction for the
years 2001 through 2003; quality-of-service standards; and
participation in a regional transmission organization.  As part of
the settlement agreement, the IURC agreed not to oppose the merger
in the FERC or SEC  proceedings.
Kentucky
   On April 15, 1999, in compliance with a request from the staff
of the Kentucky Public Service Commission (KPSC) AEP filed an
application seeking KPSC approval for the indirect change in
control of Kentucky Power Company that will occur as a result of
the proposed merger.  Although AEP did not believe that the KPSC
has the jurisdictional authority to approve the merger, AEP reached
a merger settlement agreement on May 24, 1999 with key parties in
Kentucky which the KPSC approved on June 14, 1999.  Under the terms
of the Kentucky settlement, AEP has agreed to share net merger
savings with Kentucky customers; establish performance standards
that will maintain or improve customer service and system
reliability; and to establish rules to protect consumers and
promote fair competition.  The Kentucky customers' share of the net
merger savings are expected to be approximately $28 million.  The
key parties to the Kentucky settlement agreed not to oppose the
merger during the FERC or the SEC proceedings.
Ohio
   On October 21, 1999, the Public Utilities Commission of Ohio
(PUCO) issued a decision stating that it will notify the FERC that
it will withdraw its opposition to the Company's pending merger
with CSW and will not seek conditions on the merger.
   American Municipal Power - Ohio (AMP-Ohio) and AEP reached a
settlement addressing outstanding issues.  As part of the
settlement AMP-Ohio agreed to withdraw as an intervenor in the
merger process.  AMP-Ohio is the nonprofit wholesale power supplier
and service provider for most of Ohio's 84 community-owned public
power systems, two West Virginia public power systems and four
Pennsylvania public power systems.
Other
   AEP and CSW have reached settlements with the Missouri
Commission, the International Brotherhood of Electrical Workers
(IBEW), representing employees of AEP and CSW, and the Utility
Worker's Union of America (UWUA) representing AEP employees, and
certain wholesale customers.  All have agreed not to oppose the
merger in the FERC or SEC proceedings.
   The proposed merger of CSW into AEP would result in common
ownership of two United Kingdom (UK) regional electricity companies
(RECs), Yorkshire and Seeboard, plc.  AEP has a 50% ownership
interest in Yorkshire and CSW has a 100% interest in Seeboard.
Although the merger of CSW into AEP is not subject to approval by
UK regulatory authorities, the common ownership of two UK RECs
could be referred by the UK Secretary of State for Trade and
Industry to the UK Competition Commission (formerly Monopolies and
Mergers Commission) for review and investigation.
Completion of the Merger
   As of September 30, 1999, AEP had deferred $37 million of costs
related to the merger on its consolidated balance sheet, which will
be charged to expense if AEP and CSW are not successful in
completing their proposed merger.  If the merger is consummated the
deferred costs allocable to the regulated electric operating
subsidiaries will be amortized over their recovery period,
generally 5-years, in accordance with state regulator orders.  The
remainder of the deferred merger costs will be expensed upon
consummation of the merger.
   The merger is conditioned upon, among other things, the
approval of certain state and federal regulatory agencies.  The
transaction must satisfy many conditions, a number of which may not
be waived by the parties, including the condition that the merger
must be accounted for as a pooling of interests.  The merger
agreement will terminate on December 31, 1999 unless extended for
six months by either party as provided in the merger agreement.
Although consummation of the merger is expected to occur in the
second quarter of 2000, the Company is unable to predict the
outcome or the timing of the required regulatory proceedings.
Cook Nuclear Plant Shutdown
   As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, both units of the Cook Plant
were shut down in September 1997 due to questions regarding the
operability of certain safety systems that arose during a NRC
architect engineer design inspection.  The NRC issued a
Confirmatory Action Letter in September 1997 requiring the Company
to address certain issues identified in the letter.  In 1998 the
NRC notified the Company that it had convened a Restart Panel for
Cook Plant and provided a list of required restart activities.  In
order to identify and resolve all issues, including those in the
letter, necessary to restart the Cook units, the Company is working
with the NRC and will be meeting with the Panel on a regular basis,
until the units are returned to service.
   In May 1999 the Company received a letter from the NRC
indicating that NRC senior managers had identified Cook Plant as an
"agency-focus plant."  The NRC senior managers concluded that
continued agency-level oversight was appropriate; however, the NRC
required no additional action to redirect Cook Plant activities.
The letter states that the NRC staff will continue to monitor Cook
Plant performance through the Restart Panel process and evaluate
whether additional action may be necessary.
   The Company's plan to restart the Cook Plant units has Unit 2
scheduled to return to service in April 2000 and Unit 1 to return
to service in September 2000.  The restart plan was developed based
upon a comprehensive systems readiness review of all operating
systems at the Cook Plant.  When maintenance and other activities
required for restart are complete, the Company will seek
concurrence from the NRC to return the Cook Plant to service.
   Management intends to replace the steam generator for Unit 1
before the unit is returned to service.  Costs associated with the
steam generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart.  At September 30, 1999, $82 million has
been spent on the steam generator replacement.
   The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal-based purchased power is being
substituted for the unavailable low cost nuclear generation.
Actual replacement energy fuel costs that exceeded the costs
reflected in billings have been recorded as a regulatory asset
under the Indiana and Michigan retail jurisdictional fuel cost
recovery mechanisms.
   On March 30, 1999 the IURC approved a settlement agreement that
resolves all matters related to the recovery of replacement energy
fuel costs and all outage/restart issues during the extended outage
of the Cook Plant.  The settlement agreement provides for, among
other things, a billing credit of $55 million, including interest,
to Indiana retail customers' bills; the deferral of unrecovered
fuel revenues accrued between September 9, 1997 and December 31,
1999, including a $52.3 million revenue portion of the $55 million
billing credit; the deferral of up to $150 million of incremental
operation and maintenance costs in 1999 for Cook Plant above the
amount included in base rates; the amortization of the deferred
fuel and non-fuel operation and maintenance cost deferrals over a
five-year period ending December 31, 2003; a freeze in base rates
through December 31, 2003; and a fixed fuel recovery charge through
March 1, 2004.  The $55 million credit was applied to retail
customers' bills  during the months of July, August and September
1999.
   In June 1999 the Company announced that a settlement agreement
for two open Michigan power supply cost recovery reconciliation
cases had been reached with the staff of the Michigan Public
Service Commission (MPSC).  The proposed settlement agreement would
limit the Company's ability to increase base rates and freeze power
supply costs for five years, allow for the amortization of deferred
power supply cost for 1997, 1998 and 1999 over five years, allow
for the deferral and amortization of non-fuel nuclear operation and
maintenance expenses over five years and resolve all issues related
to the Cook Plant extended restart outage. The pending Michigan
settlement limits deferrals to $50 million of 1999 jurisdictional
non-fuel nuclear operation and maintenance costs. Hearings have
been held to give the one intervenor who opposed the approval of
the settlement agreement the opportunity to voice its objections.
The settlement agreement is pending before the MPSC.
   Expenditures for the restart of the Cook units are estimated
to total approximately $574 million and will be accounted for
primarily as a current period operation and maintenance expense in
1999 and 2000.  Through September 30, 1999, $280 million has been
spent, of which $196 million was incurred in 1999.  Pursuant to the
Indiana settlement agreement $112.5 million of incremental
operation and maintenance costs were deferred for the nine months
ended September 30, 1999.  The Indiana jurisdiction deferral is
limited to up to $150 million of incremental restart costs incurred
in 1999.  The amortization of such costs through September 30, 1999
was $22.5 million.  At September 30, 1999, the unamortized balance
of incremental restart related operation and maintenance costs was
$90 million and was included in regulatory assets.  Also deferred
as a regulatory asset at September 30, 1999 was $148 million of
replacement energy fuel costs.
   The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations, cash
flows, and possibly financial condition through 2003.  Management
believes that the Cook units will be successfully returned to
service by April and September 2000, however, if for some unknown
reason the units are not returned to service or their return is
delayed significantly it would have an even greater adverse effect
on future results of operations, cash flows and financial
condition.
Restructuring Legislation
Virginia
   In March 1999 a law was enacted in Virginia to restructure the
electric utility industry.  Under the restructuring law a
transition to choice of electricity supplier for retail customers
will commence on January 1, 2002 and be completed, subject to a
finding by the Virginia State Corporation Commission that an
effective competitive market exists, on January 1, 2004.
   The law also provides an opportunity for recovery of just and
reasonable net stranded generation costs.  Stranded costs are those
costs above market including generation related regulatory assets
and impaired tangible assets that potentially would not be
recoverable in a competitive market.  The mechanisms in the
Virginia law for stranded cost recovery are: a capping of rates
until as late as July 1, 2007, and the application of a wires
charge upon customers who depart the incumbent utility in favor of
an alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior to
January 1, 2001 and the establishment of a wires charge by the
fourth quarter of 2001.
   Management has concluded that as of September 30, 1999 the
requirements to apply Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation," continue to be met.  The Company's Virginia rates for
generation will continue to be cost-based regulated until the
establishment of capped rates and the wires charge as provided in
the law.  The establishment of capped rates and the wires charge
should enable the Company to determine its ability to recover
stranded costs, a requirement to discontinue application of SFAS
71.
   When the capped rates and the wires charge are established in
Virginia, the application of SFAS 71 will be discontinued for the
Virginia retail jurisdiction portion of the Company's generating
business.  At that time the Company will have to write-off its
generation-related regulatory assets to the extent that they cannot
be recovered under capped rates and wire charges approved by the
Virginia SCC under the provisions of the restructuring law and
record any asset impairments in accordance with SFAS 121,
"Accounting for the Impairment of Long-lived Assets and for Long-lived
Assets to Be Disposed Of."  An impairment loss would be
recorded to the extent that the cost of impaired assets cannot be
recovered through the transition recovery mechanisms provided by
the law and future market prices.  Absent the determination in the
regulatory process of capped rates, wires charges and other
pertinent information, it is not possible at this time to determine
if any generation related assets are impaired in accordance with
SFAS 121 and if generation related regulatory assets will be
recovered.  The amount of regulatory assets recorded on the books
applicable to the Company's Virginia generating business at
September 30, 1999 is estimated to be $60 million before related
tax effects.
   Should it not be possible under the Virginia law to recover all
or a portion of the generation related regulatory assets and/or
tangible generating assets, it could have a material adverse impact
on results of operations.  An estimated determination of whether
the Company will experience any asset impairment loss regarding its
Virginia retail jurisdictional generating assets and any loss from
a possible inability to recover generation related regulatory
assets and other transition costs cannot be made until such time as
the transition capped rates and the wires charge are determined
under the law which is expected to be no later than the fourth
quarter of 2000.
Ohio
   The Ohio Electric Restructuring Act of 1999 became law on
October 4, 1999.  The law provides for customer choice of
electricity supplier, a residential rate reduction of 5% and a
freezing of the unbundled generation base rates and a freezing of
fuel rates beginning on January 1, 2001.  The law also provides for
a five-year transition period to transition from cost based rates
to market pricing for generation services.  It authorizes the PUCO
to address certain major transition issues including unbundling of
rates and the recovery of regulatory assets including any
unrecovered deferred fuel costs, stranded plant and mining costs
and other transition costs.
   Retail electric services that will be competitive are defined
in the law as electric generation service, aggregation service, and
power marketing and brokering.  Under the legislation the PUCO is
granted broad oversight responsibility and is required by the law
to promulgate rules for competitive retail electric generation
service.  The law also gives the PUCO authority to approve a
transition plan for each electric utility company.
   The law provides Ohio electric utilities with an opportunity
to recover PUCO approved allowable transition costs through
unbundled frozen generation rates paid through December 31, 2005 by
customers who do not switch generation suppliers and through a
wires charge for customers who switch generation suppliers.
Transition costs can include regulatory assets, impairments of
generating assets and other stranded costs, employee severance and
retraining costs, consumer education costs and other costs.
Recovery of transition costs can, under certain circumstances,
extend beyond the five-year frozen rate transition period but
cannot continue beyond December 31, 2010.  The Company must file a
transition plan with the PUCO by January 3, 2000 and the PUCO is
required to issue a transition order no later than October 31,
2000.
   The law also provides that the property tax assessment
percentage on electric generation property be lowered from 100% to
25% of value effective January 1, 2001.  Electric utilities will
become subject to the Ohio Corporate Franchise Tax and municipal
income taxes on January 1, 2002.  The last year for which electric
utilities will pay the excise tax based on gross receipts is the
tax year ending April 30, 2002.  As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on
kilowatt-hours sold to Ohio customers.  The gross receipts tax is
paid at the beginning of the tax year, deferred as a prepaid
expense and amortized to expense during the tax year pursuant to
the tax laws whereby the payment of the tax results in the
privilege to conduct business in the year following the payment of
the tax.  The change in the tax law to impose an excise tax based
on kilowatt-hours sold to Ohio customers commencing before the
expiration of the gross receipts tax privilege period will result
in a 12 month period when electric utilities are recording as an
expense both the gross receipts tax and the excise tax.  Management
intends to seek recovery of the overlap of the gross receipts and
excise taxes in the Ohio transition plan filing.
   As discussed in Note 3, "Effects of Regulation and Phase-In
Plans," of the Notes to Consolidated Financial Statements in the
1998 Annual Report, the Company defers as regulatory assets and
liabilities certain expenses and revenues consistent with the
regulatory process in accordance with SFAS 71.  Management has
concluded that as of September 30, 1999 the requirements to apply
SFAS 71 continue to be met since the Company's rates for generation
will continue to be cost-based regulated until the establishment of
unbundled frozen generation rates and a wires charge as provided in
the law.  The establishment of unbundled frozen generation rates
and the wires charge should enable the Company to determine its
ability to recover transition costs including regulatory assets and
other stranded costs, a requirement to discontinue application of
SFAS 71.
   When unbundled generation rates and the wires charge are
established, the application of SFAS 71 will be discontinued for
the Ohio retail jurisdiction portion of the  generation business.
At that time the Company will have to write-off its Ohio
jurisdictional generation-related regulatory assets to the extent
that they cannot be recovered under the unbundled frozen generation
rates and distribution wires charges approved by the PUCO under the
provisions of the restructuring law and record any asset
impairments in accordance with SFAS 121.  An impairment loss would
be recorded to the extent that the cost of generation assets cannot
be recovered through the transition recovery mechanisms provided by
the law and future market prices.  Absent the determination in the
regulatory process of an unbundled frozen generation rate, the
wires charge and other pertinent information, it is not possible at
this time to determine if any of the Company's generating assets
are impaired in accordance with SFAS 121.  The amount of regulatory
assets recorded on the books at September 30, 1999 applicable to
the Ohio retail jurisdictional generating business is $638 million
before related tax effects.  Due to the planned closing of
affiliated mines including the Meigs mine, and other anticipated
events, generation-related regulatory assets as of December 31,
2000 allocable to the Ohio retail jurisdiction are estimated to
exceed $800 million, before federal income tax effects.  Recovery
of these regulatory assets will be sought as a part of the
Company's Ohio transition plan filing.
   An estimated determination of whether the Company will
experience any asset impairment loss regarding its Ohio retail
jurisdictional generating assets and any loss from a possible
inability to recover Ohio generation related regulatory assets and
other transition costs cannot be made until such time as the
unbundled frozen generation rates and the wires charge are
determined through the regulatory process.  Management will seek
full recovery of generation-related regulatory assets, any stranded
costs and other transition costs in its transition plan filing.
The PUCO is required to complete its regulatory process and issue
a transition order establishing the transition rates and wires
charges by no later than October 31, 2000.  Should the PUCO fail to
approve transition rates and wires charges that are sufficient to
recover the Company's generation-related regulatory assets, any
other stranded costs and transition costs, it could have a material
adverse effect on results of operations, cash flows and financial
condition.
COLI Litigation
   As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the deductibility of certain
interest deductions related to American Electric Power's corporate
owned life insurance (COLI) program for taxable years 1991-1996 is
under review by the Internal Revenue Service (IRS).  Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions.  A disallowance of COLI interest deductions through
September 30, 1999 would reduce earnings by approximately $317
million (including interest).  The Company has made no provision
for any possible earnings impact from this matter.
   The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-1998 to avoid
the potential assessment by the IRS of any additional above market
rate interest on the contested amount. These payments to the IRS
are included on the Consolidated Balance Sheets in other property
and investments pending the resolution of this matter.  The Company
is seeking refunds through litigation of all amounts paid plus
interest.
   In order to resolve this issue, the Company filed suit against
the United States in the US District Court for the Southern
District of Ohio in March 1998.  A US Tax Court judge recently
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deductions should be disallowed.
Notwithstanding the decision in Winn-Dixie, management believes,
and has been  advised by outside counsel, that it has a meritorious
position and will vigorously pursue its lawsuit.  In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.

<PAGE>
Air Quality
   As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the U.S. Environmental
Protection Agency (Federal EPA) issued final rules which require
reductions in nitrogen oxides (NOx) emissions in 22 eastern states,
including the states in which the Company's generating plants are
located.  A number of utilities, including the Company, filed
petitions seeking a review of the final rules in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court).  The
matter is currently being litigated.
   On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act.  Federal EPA approved portions of the
states' petitions that would impose NOx reduction requirements on
AEP System generating units which are approximately equivalent to
the reductions contemplated by the NOx emission reduction final
rules.  The AEP System companies with generating plants, as well as
other utility companies, filed a petition in the Appeals Court
seeking review of Federal EPA's approval of portions of the
northeastern states' petitions.  In the second quarter of 1999,
three additional northeastern states filed Section 126 petitions
with Federal EPA similar to those originally filed by the eight
northeastern states.
   Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $1.5 billion for
the Company.  Compliance costs cannot be estimated with certainty.
The actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions.  Unless such costs are recovered from customers through
regulated rates, and where generation is being deregulated
unbundled generation transition rates, wires charges and the future
market price of electricity, they will have an adverse effect on
future results of operations, cash flows and possibly financial
condition.

<PAGE>
Federal EPA Complaint and Notice of Violation
   On November 3, 1999 the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company made
modifications to generating units at its Muskingum River, Mitchell,
Philip Sporn, Tanners Creek and Cardinal plants over the course of
the past 25 years to extend unit operating lives or to increase
unit generating capacity without a preconstruction permit in
violation of the Clean Air Act.  Federal EPA also issued a Notice
of Violation to the Company alleging violations of the New Source
Review and New Source Performance Standard provisions of the Clean
Air Act at these same plants as well as Conesville Plant.  A number
of unaffiliated utilities also received Notices of Violation,
complaints or administrative orders including a Notice of Violation
issued to The Cincinnati Gas & Electric Company for Beckjord Plant
alleging violations of the New Source Review provisions of the
Clean Air Act.  Columbus Southern Power Company owns a partial
interest in Unit 6 of Beckjord Plant.
   Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to assess
compliance with the New Source Review and New Source Performance
Standard provisions of the Clean Air Act.  Under these provisions
of the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting
requirements under the New Source Review program might be triggered
and the plant may be required to install additional pollution
control technology.  This requirement does not apply to activities
such as routine maintenance, replacement of degraded equipment or
failed components, or other repairs needed for the reliable, safe
and efficient operation of the plant.
   In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each separately
threatened to sue the Company under the Clean Air Act to compel
compliance with the New Source Review and New Source Performance
Standard provisions, alleging that modifications occurred at
certain units at the Company's Philip Sporn Plant, Kammer Plant,
Mitchell Plant, Muskingum River Plant, Gavin Plant, Cardinal Plant,
Clinch River Plant, Kanawha River Plant, Tanners Creek Plant, Amos
Plant and Big Sandy Plant.  The State of New York also threatened
to sue five unaffiliated utilities.  In addition, the State of New
York indicated that it may seek to recover, under state law,
compensation for alleged environmental damage caused by excess
emissions of sulfur dioxide and nitrogen oxides.
   Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its defense
of this matter.
   The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997).  Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be  substantial.
   In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates, and where states are deregulating generation, approved
unbundled transition generation rates, wires charges and future
market prices for energy.
Market Risks
   The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices, foreign
currency exchange rates and interest rates.  Market risk represents
the risk of loss that may impact the Company due to adverse changes
in commodity market prices, foreign currency exchange rates and
interest rates.
   The Company's exposure to market risk from the trading of
electricity, natural gas and related financial derivative
instruments has not changed materially since December 31, 1998.
   There have been no material changes to the Company's exposure
to fluctuation in foreign currency exchange rates related to
foreign ventures and investments since December 31, 1998.
   The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at September 30, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
   On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date.  In
addition, certain systems may fail to detect that the year 2000 is
a leap year.  Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.

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

   Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
AEP, along with other electric utilities in North America, has
submitted information to the North American Electric Reliability
Council (NERC) as part of NERC's Y2K readiness program.  NERC then
publicly reported summary information to the DOE regarding the Y2K
readiness of electric utilities.  The fourth and final NERC report,
dated August 3, 1999 and entitled: Preparing the Electric Power
Systems of North America for Transition to the Year 2000 - A Status
Report and Work Plan, Second Quarter 1999 states that: "Mission-critical
component testing indicates that the transition through
critical Y2K dates is expected to have minimal impact on electric
system operations in North America."  The report also indicates
that, "the risk of electrical outages caused by Y2K appears to be
no higher than the risks we already experience" from incidents such
as severe wind, ice, floods, equipment failures and power shortages
during an extremely hot or cold period.  NERC has classified AEP as
a "Y2K Ready" organization with respect to its electric systems.
   AEP participated in an industry-wide NERC-sponsored drill on
April 9, 1999 simulating the partial loss of voice and data
communications.  There were no major problems encountered with
relaying information with the use of backup telecommunications
systems.  AEP and other utilities also participated in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.  The drill gave
electric utilities in North America an opportunity to test how
workers would respond in emergency situations, such as an outage at
a major power plant or loss of the normal communications system.
The drill did not reveal any major problems or issues for AEP.
   Through the Electric Power Research Institute, AEP is
participating in an electric utility industry-wide effort that has
been established to deal with Y2K problems affecting embedded
systems.  The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.

   Company's State of Readiness - Work has been prioritized in
accordance with business risk.  The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.

   Except for AEP's Louisiana gas operations and CitiPower, AEP
has completed the process of modifying, replacing or retiring and
testing its mission critical and high priority digital-based
systems with problems processing dates in the Year 2000.

   The mission critical systems for the Louisiana gas operations
are expected to be ready by December 10, 1999 and the mission
critical systems for CitiPower are expected to be ready by November
30, 1999.

   The Company has upgraded its meteorological reporting system
used at the Donald C. Cook Nuclear Plant, a mission critical IT
system, for Y2K readiness.  It was originally anticipated that the
upgrade was to have been completed by December 15, 1999.

   Costs to Address the Company's Y2K Issues - Through September
30, 1999, the Company has spent $41 million on the Y2K project and
estimates spending an additional $7 million to $15 million to
achieve Y2K readiness.  Most Y2K costs are for software, IT
consultants and salaries and are expensed; however, in certain
cases the Company has acquired hardware that was capitalized.  The
Company intends to fund these expenditures through internal
sources.  The cost of becoming Y2K 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 Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
   Automated power generation, transmission and distribution
   systems
   Telecommunications systems
   Energy trading systems
   Time-in-use, demand and remote metering systems for
   commercial and industrial customers
   Work management and billing systems.

   The potential problems related to erroneous processing by, or
failure of, these systems are:
   Power service interruptions to customers
   Interrupted revenue data gathering and collection
   Poor customer relations resulting from delayed billing and
   settlement.
   Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restorable in a reasonable
period of time.
   CitiPower operates under a legal and regulatory system which
may expose it to customer claims for service interruptions and/or
power quality problems resulting from Y2K problems.  Such claims
differ from claims under the US legal and regulatory system.

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

   Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a Y2K contingency plan and
submitted it to the East Central Area Reliability Council (ECAR) as
part of NERC's review of regional and individual electric utility
contingency plans in 1999.  In addition, the Company has
established detailed contingency plans for its business units to
address alternatives if Y2K related failures occur, including an
operating plan which is coordinated with other ECAR member
utilities.  These contingency plans will be refined by the end of
1999.
   AEP's Y2K contingency plans build upon the disaster recovery,
system restoration, and contingency planning that we have had in
place and include:
   Availability of additional power generation reserves.
   Coal inventory of approximately 45 days of normal usage.
   Identifying critical operational locations, in order to place
   key employees on duty at those locations during the Y2K
   transition.

<PAGE>
<PAGE>
<TABLE>
                          AEP GENERATING COMPANY
                           STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                           Three Months Ended      Nine Months Ended
                                              September 30,          September 30,
                                             1999      1998         1999        1998
                                                         (in thousands)
<S>                                        <C>        <C>         <C>         <C>
OPERATING REVENUES . . . . . . . . . . .   $57,235    $59,262     $161,674    $167,596

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    28,556     27,953       68,983      71,718
  Rent - Rockport Plant Unit 2 . . . . .    17,071     17,071       51,212      51,212
  Other Operation. . . . . . . . . . . .     2,447      2,174        7,909       7,547
  Maintenance. . . . . . . . . . . . . .     1,457      2,703        8,208       9,110
  Depreciation . . . . . . . . . . . . .     5,459      5,405       16,382      16,229
  Taxes Other Than Federal Income Taxes.     1,398        882        3,890       2,759
  Federal Income Tax Expense (Credit). .       (74)       845          807       2,562

          TOTAL OPERATING EXPENSES . . .    56,314     57,033      157,391     161,137

OPERATING INCOME . . . . . . . . . . . .       921      2,229        4,283       6,459

NONOPERATING INCOME. . . . . . . . . . .       885        837        2,630       2,457

INCOME BEFORE INTEREST CHARGES . . . . .     1,806      3,066        6,913       8,916

INTEREST CHARGES . . . . . . . . . . . .       848        903        2,119       2,494

NET INCOME . . . . . . . . . . . . . . .   $   958    $ 2,163     $  4,794    $  6,422



                      STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended      Nine Months Ended
                                              September 30,          September 30,
                                             1999      1998         1999        1998
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . .    $4,460    $2,435       $2,770      $2,528

NET INCOME . . . . . . . . . . . . . . .       958     2,163        4,794       6,422

CASH DIVIDENDS DECLARED. . . . . . . . .     2,073     2,176        4,219       6,528

BALANCE AT END OF PERIOD . . . . . . . .    $3,345    $2,422       $3,345      $2,422



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

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                          AEP GENERATING COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                            September 30,  December 31,
                                                                 1999          1998
                                                                   (in thousands)

ASSETS
<S>                                                           <C>            <C>
ELECTRIC UTILITY PLANT:
  Production. . . . . . . . . . . . . . . . . . . . . . . .   $627,950       $630,260
  General . . . . . . . . . . . . . . . . . . . . . . . . .      1,941          2,009
  Construction Work in Progress . . . . . . . . . . . . . .      7,524          4,191
          Total Electric Utility Plant. . . . . . . . . . .    637,415        636,460
  Accumulated Depreciation. . . . . . . . . . . . . . . . .    289,255        277,855


          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .    348,160        358,605




CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .      1,988            232
  Accounts Receivable . . . . . . . . . . . . . . . . . . .     22,122         22,894
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .     19,174         11,308
  Materials and Supplies. . . . . . . . . . . . . . . . . .      3,920          3,900
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .         33            267


          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     47,237         38,601



REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      5,804          5,984



DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      1,741            702



            TOTAL . . . . . . . . . . . . . . . . . . . . .   $402,942       $403,892

See Notes to Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
                          AEP GENERATING COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                           September 30,   December 31,
                                                                1999           1998
                                                                  (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                           <C>            <C>
CAPITALIZATION:
  Common Stock - Par Value $1,000:
    Authorized and Outstanding - 1,000 Shares . . . . . . .   $  1,000       $  1,000
  Paid-in Capital . . . . . . . . . . . . . . . . . . . . .     29,235         35,235
  Retained Earnings . . . . . . . . . . . . . . . . . . . .      3,345          2,770
          Total Common Shareholder's Equity . . . . . . . .     33,580         39,005
  Long-term Debt. . . . . . . . . . . . . . . . . . . . . .       -            44,792

          TOTAL CAPITALIZATION. . . . . . . . . . . . . . .     33,580         83,797

OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . .        653            896

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .     44,798           -
  Short-term Debt - Notes Payable . . . . . . . . . . . . .     13,825         24,450
  Accounts Payable:
    General . . . . . . . . . . . . . . . . . . . . . . . .      5,209          6,419
    Affiliated Companies. . . . . . . . . . . . . . . . . .     14,277          6,177
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      6,146          3,227
  Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . .     23,427          4,963
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      3,775          6,023

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .    111,457         51,259

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . .    129,152        133,330

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits . . . . . . . . . . . . .     64,046         66,562
  Deferred Amounts Due to Customers for Income Tax. . . . .     26,910         28,644

          TOTAL REGULATORY LIABILITIES. . . . . . . . . . .     90,956         95,206

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     37,144         39,404

            TOTAL . . . . . . . . . . . . . . . . . . . . .   $402,942       $403,892

See Notes to Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
                          AEP GENERATING COMPANY
                         STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                 Nine Months Ended
                                                                   September 30,
                                                                 1999          1998
                                                                   (in thousands)
<S>                                                            <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .   $  4,794      $  6,422
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . . .     16,382        16,229
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     (3,994)        3,975
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (2,516)       (2,522)
    Amortization of Deferred Gain on Sale
      and Leaseback - Rockport Plant Unit 2. . . . . . . . .     (4,178)       (4,178)
    Deferred Property Taxes. . . . . . . . . . . . . . . . .       (827)         (794)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable. . . . . . . . . . . . . . . . . . .        772        (1,964)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     (7,886)       (1,870)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .      6,890         3,522
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .      2,919         1,331
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .     18,464        18,464
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     (2,549)        1,968
        Net Cash Flows From Operating Activities . . . . . .     28,271        40,583

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .     (5,671)       (4,829)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .       -            2,254
        Net Cash Flows Used For Investing Activities . . . .     (5,671)       (2,575)

FINANCING ACTIVITIES:
  Return of Capital to Parent Company. . . . . . . . . . . .     (6,000)       (3,000)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .       -          (25,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (10,625)       (3,575)
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .     (4,219)       (6,528)
        Net Cash Flows Used For Financing Activities . . . .    (20,844)      (38,103)

Net Increase (Decrease) in Cash and Cash Equivalents . . . .      1,756           (95)
Cash and Cash Equivalents at Beginning of Period . . . . . .        232           237
Cash and Cash Equivalents at End of Period . . . . . . . . .   $  1,988      $    142


Supplemental Disclosure:
  Cash paid  (received) for interest  net  of capitalized  amounts was $1,889,000 and
  $2,508,000 and for income  taxes was $4,458,000 and $(1,188,000) in  1999 and 1998,
  respectively.

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
                          AEP GENERATING COMPANY
                       NOTES TO FINANCIAL STATEMENTS
                             SEPTEMBER 30, 1999
                                (UNAUDITED)

1. GENERAL

   The accompanying unaudited financial statements should be read in
conjunction with the 1998 Annual Report as incorporated in and filed with the
Form 10-K.  Certain prior-period amounts have been reclassified to conform to
current-period presentation.  In the opinion of management, the financial
statements reflect all normal recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for interim
periods.

2. FINANCING ACTIVITIES

   Under the terms of installment purchase contracts, the Company is
required to pay the City of Rockport amounts sufficient to enable the payment
of interest and principal on pollution control revenue bonds issued to
finance the construction costs of pollution control facilities at the
Rockport Plant.  On the Series 1995 A and B bonds the principal is payable at
maturity (July 1, 2025) or on the demand of the bondholders.  The Company has
agreements that provide for brokers to remarket bonds tendered.  In the event
the bonds cannot be remarketed, the Company has a standby bond purchase
agreement with a bank that provides for the bank to purchase any bonds not
remarketed.  The purchase agreement expires in 2000.  Therefore, the
installment purchase contracts have been classified as due within one year.




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

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

   Operating revenues are derived from the sale of Rockport Plant energy and
capacity to two affiliated companies and one unaffiliated utility pursuant to
Federal Energy Regulatory Commission (FERC) approved long-term unit power
agreements.  The unit power agreements provide for recovery of costs
including a FERC approved rate of return on common equity and a return on
other capital net of temporary cash investments.
   Net income decreased $1.2 million or 56% for the third quarter and $1.6
million or 25% for the year-to-date period as a result of the return of
capital to the parent company in 1998, February 1999 and May 1999 and the
reduction of revenues under the long-term power agreement.
   Income statement line items which changed significantly were:

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

Operating Revenues. . . . .  $(2.0)      (3)      $(5.9)      (4)
Fuel Expense. . . . . . . .    0.6        2        (2.7)      (4)
Other Operation Expense . .    0.3       13         0.4        5
Maintenance Expense . . . .   (1.2)     (46)       (0.9)     (10)
Taxes Other Than Federal
 Income Taxes . . . . . . .    0.5       59         1.1       41
Federal Income Taxes. . . .   (0.9)    (109)       (1.8)     (69)
Interest Charges. . . . . .   (0.1)      (6)       (0.4)     (15)

   The decrease in operating revenues for the third quarter results from the
recovery through the unit power agreements of less return on common equity
reflecting the return of capital and less return on other capital reflecting
lower interest charges due to the retirement of debt.  In the year-to-date
period, operating revenues declined reflecting the lower returns on common
equity and other capital and a reduction in recoverable operating expenses.
   Fuel expense increased in the third quarter due to increases in
generation and average cost of fuel.  The increase in generation is
attributable to an increase in the availability of the Rockport Plant units.
The rise in the cost of fuel results from fluctuations in the market price of
coal.  In the year-to-date period a 6% reduction in generation, due to
planned maintenance outages in the first and second quarters of 1999 at both
units, reduced fuel expense.
   The increase in other operation expense in both the quarter and
year-to-date periods is primarily due to the effect of unfavorable accrual
adjustments for a FERC operating assessment and allocated employee benefits.
   Maintenance expense decreased due to a decline in maintenance repair and
staff expenditures reflecting the effect of staffing reductions.
   Taxes other than federal income taxes increased due to an increase in
state income taxes which resulted from an increase in taxable income due to
the completion of state tax depreciation for Rockport Plant Unit 1.
   Federal income taxes attributable to operations decreased due to a
decrease in pre-tax operating income and the amortization of deferred taxes
in excess of the statutory tax rate.
   The decline in interest charges in the year-to-date period was primarily
due to a reduction in outstanding long-term debt balances reflecting the
redemption of $25 million in March 1998 of pollution control revenue bonds.

<PAGE>
<PAGE>
<TABLE>
                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                           Three Months Ended       Nine Months Ended
                                             September 30,            September 30,
                                           1999         1998        1999         1998
                                                         (in thousands)
<S>                                      <C>           <C>        <C>          <C>
OPERATING REVENUES . . . . . . . . . . . $441,435      $474,476   $1,242,903   $1,292,922

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .  108,701       113,059      331,933      322,459
  Purchased Power. . . . . . . . . . . .   93,041       101,779      204,680      258,275
  Other Operation. . . . . . . . . . . .   59,090        73,988      182,001      191,297
  Maintenance. . . . . . . . . . . . . .   26,240        30,691       93,112       97,519
  Depreciation and Amortization. . . . .   37,700        36,059      111,475      107,252
  Taxes Other Than Federal Income Taxes.   29,201        29,003       89,242       89,181
  Federal Income Taxes . . . . . . . . .   21,153        18,946       49,445       45,547

          TOTAL OPERATING EXPENSES . . .  375,126       403,525    1,061,888    1,111,530

OPERATING INCOME . . . . . . . . . . . .   66,309        70,951      181,015      181,392
NONOPERATING INCOME (LOSS) . . . . . . .    1,925        (5,664)       1,152       (4,490)
INCOME BEFORE INTEREST CHARGES . . . . .   68,234        65,287      182,167      176,902
INTEREST CHARGES . . . . . . . . . . . .   32,573        31,841       96,209       95,133
NET INCOME . . . . . . . . . . . . . . .   35,661        33,446       85,958       81,769
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      667           675        2,015        1,822
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 34,994      $ 32,771   $   83,943   $   79,947


               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended        Nine Months Ended
                                             September 30,             September 30,
                                           1999         1998        1999          1998
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $167,714     $195,262    $179,461      $207,544
NET INCOME . . . . . . . . . . . . . . .   35,661       33,446      85,958        81,769
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   30,348       29,729      91,044        89,187
    Cumulative Preferred Stock . . . . .      558          567       1,690         1,499
  Capital Stock Expense. . . . . . . . .      109          108         325           323

BALANCE AT END OF PERIOD . . . . . . . . $172,360     $198,304    $172,360      $198,304

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

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                               1999           1998
                                                                 (in thousands)
ASSETS
<S>                                                         <C>            <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .      $2,007,970     $1,979,180
  Transmission . . . . . . . . . . . . . . . . . . . .       1,139,940      1,118,726
  Distribution . . . . . . . . . . . . . . . . . . . .       1,686,801      1,641,523
  General. . . . . . . . . . . . . . . . . . . . . . .         240,726        228,464
  Construction Work in Progress. . . . . . . . . . . .         123,378        119,466
          Total Electric Utility Plant . . . . . . . .       5,198,815      5,087,359
  Accumulated Depreciation and Amortization. . . . . .       2,061,813      1,984,856

          NET ELECTRIC UTILITY PLANT . . . . . . . . .       3,137,002      3,102,503



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         132,612        111,020



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          30,850          7,755
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         111,847        122,746
    Affiliated Companies . . . . . . . . . . . . . . .          20,854         35,802
    Miscellaneous. . . . . . . . . . . . . . . . . . .          13,400          8,572
    Allowance for Uncollectible Accounts . . . . . . .          (2,981)        (2,234)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .          56,387         49,826
  Materials and Supplies . . . . . . . . . . . . . . .          62,256         60,440
  Accrued Utility Revenues . . . . . . . . . . . . . .          40,576         45,985
  Energy Marketing and Trading Contracts . . . . . . .          95,526         22,436
  Prepayments. . . . . . . . . . . . . . . . . . . . .           9,665          8,151

          TOTAL CURRENT ASSETS . . . . . . . . . . . .         438,380        359,479


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         417,551        433,516


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .          27,805         40,520

            TOTAL. . . . . . . . . . . . . . . . . . .      $4,153,350     $4,047,038

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                        September 30,   December 31,
                                                             1999           1998
                                                               (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                      <C>             <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  30,000,000 Shares
    Outstanding - 13,499,500 Shares. . . . . . . . . .   $  260,458      $  260,458
  Paid-in Capital. . . . . . . . . . . . . . . . . . .      689,099         663,633
  Retained Earnings. . . . . . . . . . . . . . . . . .      172,360         179,461
          Total Common Shareholder's Equity. . . . . .    1,121,917       1,103,552
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .       18,575          19,359
    Subject to Mandatory Redemption. . . . . . . . . .       22,310          22,310
  Long-term Debt . . . . . . . . . . . . . . . . . . .    1,439,573       1,472,451

          TOTAL CAPITALIZATION . . . . . . . . . . . .    2,602,375       2,617,672

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .      133,558         120,281

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .      176,005          80,004
  Short-term Debt. . . . . . . . . . . . . . . . . . .      119,380          76,400
  Accounts Payable - General . . . . . . . . . . . . .       48,736          60,569
  Accounts Payable - Affiliated Companies. . . . . . .       34,564          50,313
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       33,944          35,719
  Customer Deposits. . . . . . . . . . . . . . . . . .       12,831          14,123
  Interest Accrued . . . . . . . . . . . . . . . . . .       30,245          19,990
  Revenue Refunds Accrued. . . . . . . . . . . . . . .         -             95,267
  Energy Marketing and Trading Contracts . . . . . . .       91,941          24,076
  Other. . . . . . . . . . . . . . . . . . . . . . . .       67,527          78,808

          TOTAL CURRENT LIABILITIES. . . . . . . . . .      615,173         535,269

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      648,203         643,711

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       58,715          62,231

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       95,326          67,874

CONTINGENCIES (Note 6)

            TOTAL. . . . . . . . . . . . . . . . . . .   $4,153,350      $4,047,038

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                  Nine Months Ended
                                                                    September 30,
                                                                 1999           1998
                                                                    (in thousands)
<S>                                                           <C>             <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $  85,958       $ 81,769
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    112,264        108,158
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     10,947         (1,452)
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (3,516)        (3,548)
    Provision for Rate Refunds . . . . . . . . . . . . . . .      5,139          9,342
    Deferred Power Supply Costs (net). . . . . . . . . . . .     27,715         25,137
    Amortization of Deferred Property Taxes. . . . . . . . .     13,302         12,940
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .     21,766          3,840
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     (8,377)        (7,025)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .      5,409         10,578
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (27,582)       (16,191)
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . .    (95,267)        39,107
  Payment of Disputed Tax and Interest Related to COLI . . .     (4,124)       (68,316)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .    (22,882)        24,056
        Net Cash Flows From Operating Activities . . . . . .    120,752        218,395

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (134,645)      (138,297)
  Proceeds from Sale of Property . . . . . . . . . . . . . .        274            914
        Net Cash Flows Used For Investing Activities . . . .   (134,371)      (137,383)

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .     25,000         25,000
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    148,751        193,431
  Change in Short-term Debt (net). . . . . . . . . . . . . .     42,980        (68,325)
  Retirement of Cumulative Preferred Stock . . . . . . . . .       (587)          (229)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (86,687)      (138,472)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (91,044)       (89,187)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,699)        (1,710)
        Net Cash Flows From (Used For) Financing Activities.     36,714        (79,492)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     23,095          1,520
Cash and Cash Equivalents at Beginning of Period . . . . . .      7,755          6,947
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  30,850      $   8,467

Supplemental Disclosure:
  Cash paid for  interest net of capitalized  amounts was  $83,069,000 and $83,359,000
  and for income taxes was $33,996,000 and $38,378,000 in 1999 and 1998, respectively.
  Noncash acquisitions under  capital leases were $12,132,000 and  $16,909,000 in 1999
  and 1998, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
            APPALACHIAN POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        SEPTEMBER 30, 1999
                           (UNAUDITED)

1. GENERAL

       The accompanying unaudited consolidated financial
   statements should be read in conjunction with the 1998 Annual
   Report as incorporated in and filed with the Form 10-K.
   Certain prior-period amounts have been reclassified to conform
   to current-period presentation.  In the opinion of management,
   the financial statements reflect all normal recurring accruals
   and adjustments which are necessary for a fair presentation of
   the results of operations for interim periods.

2. VIRGINIA RESTRUCTURING

       As discussed in Note 2 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, in February
   1999 the Virginia legislature passed comprehensive legislation,
   which became law in March  1999, to restructure the electric
   utility industry.  Under the restructuring law a transition to
   choice of electricity supplier for retail customers will
   commence on January 1, 2002 and be completed, subject to a
   finding by the Virginia State Corporation Commission (Virginia
   SCC) that an effective competitive market exists, on January
   1, 2004.

       The law also provides an opportunity for recovery of just
   and reasonable net stranded generation costs.  Stranded costs
   are those costs above market including generation related
   regulatory assets and impaired tangible assets that potentially
   would not be recoverable in a competitive market.  The
   mechanisms in the Virginia law for stranded cost recovery are:
   a capping of rates until as late as July 1, 2007, and the
   application of a wires charge upon customers who depart the
   incumbent utility in favor of an alternative supplier prior to
   the termination of the rate cap.  The law provides for the
   establishment of capped rates prior to January 1, 2001 and the
   establishment of a wires charge by the fourth quarter of 2001.

       Management has concluded that as of September 30, 1999 the
   requirements to apply Statement of Financial Accounting
   Standards (SFAS) 71, "Accounting for the Effects of Certain
   Types of Regulation," continue to be met.  The Company's
   Virginia rates for generation will continue to be cost-based
   regulated until the establishment of capped rates and the wires
   charge as provided in the law.  The establishment of capped
   rates and the wires charge should enable the Company to
   determine its ability to recover stranded costs, a requirement
   to discontinue application of SFAS 71.

<PAGE>
       When the capped rates and the wires charge are established
   in Virginia, the application of SFAS 71 will be discontinued
   for the Virginia retail jurisdiction portion of the Company's
   generating business.  At that time the Company will have to
   write-off its generation-related regulatory assets to the
   extent that they cannot be recovered under capped rates and
   wire charges approved by the Virginia SCC under the provisions
   of the restructuring law and record any asset impairments in
   accordance with SFAS 121, "Accounting for the Impairment of
   Long-lived Assets and for Long-lived Assets to Be Disposed Of."
   An impairment loss would be recorded to the extent that the
   cost of impaired assets cannot be recovered through the
   transition recovery mechanisms provided by the law and future
   market prices.  Absent the determination in the regulatory
   process of capped rates, wires charges and other pertinent
   information, it is not possible at this time to determine if
   any generation related assets are impaired in accordance with
   SFAS 121 and if generation related regulatory assets will be
   recovered.  The amount of regulatory assets recorded on the
   books applicable to the Company's Virginia retail generating
   business at September 30, 1999 is estimated to be $60 million
   before related tax effects.

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

3. RATE MATTER

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

       On July 9, 1996, the AEP System companies filed an Open
   Access Transmission Tariff conforming with the FERC's pro-forma
   transmission tariff, subject to the resolution of certain
   pricing issues.  The 1996 tariff incorporated transmission
   rates which were the result of a settlement of a pending rate
   case, but which were being collected subject to refund from
   certain customers who opposed the settlement and continued to
   litigate the reasonableness of AEP's transmission rates.  On
   July 29, 1999, the FERC issued an order in the litigated rate
   case which would reduce AEP's rates for the affected customers
   below the settlement rate.  AEP and certain of the affected
   customers have sought rehearing of the Commission's Order.  The
   Company made a provision in September 1999 for its share of the
   refund which it anticipates would result if the Commission's
   order is upheld including interest.

4. FINANCING ACTIVITIES

       In May 1999 the Company issued $150 million of 6.60% senior
   unsecured notes due 2009.  During the first nine months of
   1999, the Company reacquired the following first mortgage
   bonds:
                                        Principal
                                        Amount
       % Rate      Due Date         Reacquired
                                      (in thousands)
       8.43        June 1, 2022     $37,471
       7.80        May 1, 2023            9,763
       7.90        June 1, 2023      30,000
       7.15        November 1, 2023  10,000

       In September 1999, the Company received a $25 million cash
   capital contribution from its parent which was credited to
   paid-in capital.

       In October 1999 the Company issued $50 million of 7.45%
   senior unsecured notes due 2004.

       During the first nine months of 1999, the Company increased
   short-term debt by $43 million.

5. NEW ACCOUNTING STANDARDS

       In the first quarter of 1999 the Company adopted the
   Financial Accounting Standards Board's Emerging Issues Task
   Force Consensus (EITF) 98-10, "Accounting for Contracts
   Involved in Energy Trading and Risk Management Activities". The
   EITF requires that all energy trading contracts be marked-to-market.
   The effect on the Consolidated Statements of Income
   of marking open trading contracts to market is deferred as
   regulatory assets or liabilities for the portion of those open
   trading transactions within the AEP Power Pool's marketing area
   that are included in cost of service on a settlement basis for
   ratemaking purposes in the Company's non-Virginia
   jurisdictions.  A Virginia jurisdiction net mark-to-market pre-tax gain
   of $1.4 million as of September 30, 1999 is included
   in net income as a result of an agreed prohibition against
   establishing new regulatory assets in a February 1999 Virginia
   SCC approved settlement agreement.  Open contracts outside of
   AEP Power Pool's marketing area are marked-to-market in non-operating
   income.  The adoption of the EITF did not have a
   material effect on results of operations, cash flows or
   financial condition.

6. CONTINGENCIES

   Litigation

       As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the
   deductibility of certain interest deductions related to
   American Electric Power's corporate owned life insurance (COLI)
   program for taxable years 1991-1996 is under review by the
   Internal Revenue Service (IRS).  Adjustments have been or will
   be proposed by the IRS disallowing COLI interest deductions.
   A disallowance of COLI interest deductions through September
   30, 1999 would reduce earnings by approximately $79 million
   (including interest).  The Company has made no provision for
   any possible earnings impact from this matter.

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

       In order to resolve this issue, the Company filed suit
   against the United States in the US District Court for the
   Southern District of Ohio in March 1998. A US Tax Court judge
   recently decided in the Winn-Dixie Stores v. Commissioner case
   that a corporate taxpayer's COLI interest deductions should be
   disallowed.  Notwithstanding the decision in Winn-Dixie,
   management believes, and has been  advised by outside counsel,
   that it has a meritorious position and will vigorously pursue
   its lawsuit.  In the event the resolutions of this matter is
   unfavorable, it will have a material adverse impact on results
   of operations and cash flows.

   Air Quality

       As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the U.S.
   Environmental Protection Agency (Federal EPA) issued final
   rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which
   the generating plants of the Company and its AEP System
   affiliates are located.  A number of utilities, including the
   Company and its AEP System affiliates , filed petitions seeking
   a review of the final rules in the U.S. Court of Appeals for
   the District of Columbia Circuit (Appeals Court).  The matter
   is currently being litigated.

       On April 30, 1999, Federal EPA took final action with
   respect to petitions filed by eight northeastern states
   pursuant to Section 126 of the Clean Air Act.  Federal EPA
   approved portions of the states' petitions that would impose
   NOx reduction requirements on AEP System generating units which
   are approximately equivalent to the reductions contemplated by
   the NOx emission reduction final rules.  The AEP System
   companies with generating plants, as well as other utility
   companies, filed a petition in the Appeals Court seeking review
   of Federal EPA's approval of portions of the northeastern
   states' petitions.  In the second quarter of 1999, three
   additional northeastern states filed Section 126 petitions with
   Federal EPA similar to those originally filed by the eight
   northeastern states.

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

   Federal EPA Complaint and Notice of Violation

       On November 3, 1999 the Department of Justice, at the
   request of Federal EPA, filed a complaint in the U.S. District
   Court for the Southern District of Ohio that alleges the
   Company made modifications to generating units at its Philip
   Sporn Plant over the course of the past 25 years to extend unit
   operating lives or to increase unit generating capacity without
   a preconstruction permit in violation of the Clean Air Act.
   Federal EPA also issued a Notice of Violation to the Company
   alleging violations of the New Source Review and New Source
   Performance Standard provisions of the Clean Air Act at this
   plant.  A number of unaffiliated utilities also received
   Notices of Violation, complaints or administrative orders.

       Federal EPA's Notice of Violation and the government's
   complaint are based on an investigation by Federal EPA to
   assess compliance with the New Source Review and New Source
   Performance Standard provisions of the Clean Air Act.  Under
   these provisions of the Clean Air Act, if a plant undertakes
   a major modification that directly results in an emissions
   increase, permitting requirements under the New Source Review
   program might be triggered and the plant may be required to
   install additional pollution control technology.  This
   requirement does not apply to activities such as routine
   maintenance, replacement of degraded equipment or failed
   components, or other repairs needed for the reliable, safe and
   efficient operation of the plant.

       In the fall of 1999 the State of New York, various
   environmental groups and the State of Connecticut each
   separately threatened to sue the Company under the Clean Air
   Act to compel compliance with the New Source Review and New
   Source Performance Standard provisions, alleging that
   modifications occurred at certain units at the Company's Clinch
   River Plant, Kanawha River Plant and Amos Plant.  The State of
   New York also threatened to sue five unaffiliated utilities.
   In addition, the State of New York indicated that it may seek
   to recover, under state law, compensation for alleged
   environmental damage caused by excess emissions of sulfur
   dioxide and nitrogen oxides.

       Management believes its maintenance, repair and replacement
   activities were in conformity with the Clean Air Act and were
   exempted from the New Source Review and New Source Performance
   Standard requirements, and intends to vigorously pursue its
   defense of this matter.

       The Clean Air Act authorizes civil penalties of up to
   $27,500 per day per violation at each generating unit ($25,000
   per day prior to January 30, 1997).  Civil penalties, if
   ultimately imposed by the court, and the cost of any required
   new pollution control equipment, if the court accepts all of
   Federal EPA's contentions, could be  substantial.

       In the event the Company does not prevail, any capital and
   operating costs of additional pollution control equipment that
   may be required as well as any penalties imposed would
   adversely affect future results of operations, cash flows and
   possibly financial condition unless such costs can be recovered
   through regulated rates, and where generation is being
   deregulated, approved unbundled transition generation rates,
   wires charges and future market prices for energy.

   Other

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

<PAGE>
<PAGE>
            APPALACHIAN POWER COMPANY AND SUBSIDIARIES
  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                     AND FINANCIAL CONDITION
            THIRD QUARTER 1999 vs. THIRD QUARTER 1998
                               AND
             YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
   Net income increased $2.2 million or 7% for the quarter and
$4.2 million or 5% for the year-to-date period primarily due to an
increase in sales to retail customers, a decline in operating
expenses and an increase in nonoperating income.
   Income statement line items which changed significantly were:
                                   Increase (Decrease)
                             Third Quarter       Year-to-Date
                          (in millions)   %   (in millions)   %

Operating Revenues . . . .   $(33.0)     (7)     $(50.0)     (4)
Fuel Expense . . . . . . .     (4.4)     (4)        9.5       3
Purchased Power Expense. .     (8.7)     (9)      (53.6)    (21)
Other Operation Expense. .    (14.9)    (20)       (9.3)     (5)
Maintenance Expense. . . .     (4.5)    (15)       (4.4)     (5)
Federal Income Taxes . . .      2.2      12         3.9       9
Nonoperating Income (Loss)      7.6     134         5.6     126

   Operating revenues decreased in both the third quarter and the
year-to-date periods due predominantly to a decline in wholesale
power sales margins and a revenue refund provision for wholesale
transmission service.  Also contributing to the year-to-date
decrease in wholesale revenues was the termination of a contract
with several municipal customers effective July 1, 1998.  These
decreases in wholesale power revenues and sales were partially
offset by increases in retail revenues from increased energy sales
to residential and commercial customers reflecting changes in the
weather.  Colder winter weather and warmer summer temperatures led
to increased energy usage by residential and commercial customers.
   The decrease in fuel expense for the quarter was due to a lower
average cost of fuel consumed and a reduction in the over recovery
of power supply costs in the West Virginia retail jurisdiction
through the operation of the West Virginia power supply cost
recovery mechanism, partially offset by increased fuel consumed for
additional generation.  A decline in the market price of coal
accounted for the decrease in the average cost of fuel consumed.
Pursuant to the West Virginia retail jurisdictional power supply
cost recovery mechanism, over collections of power supply costs are
deferred for future refund to customers through a charge to fuel
expense.  The over recovery of West Virginia non-fuel power supply
costs declined in the third quarter primarily due to the decreased
wholesale energy sales and margins on off-system sales included in
the West Virginia power supply cost recovery mechanism.  Also in
the third quarter, fuel expense rose due to increased coal fired
generation to meet the increased retail demand resulting from the
warmer summer weather.  In the year-to-date period, fuel expense
rose primarily due to increased coal fired generation to meet the
increased retail demand resulting from the first quarter's colder
winter weather and the warmer summer weather.
   Purchased power expense decreased primarily as a result of
decreased purchases from the American Electric Power (AEP) System
Power Pool (AEP Power Pool), reflecting increased generation, and
a decline in capacity charges paid to the AEP Power Pool.  Under
the terms of the AEP Power Pool, capacity credits and charges are
designed to allocate the cost of the AEP System's capacity among
the AEP Power Pool members based on their relative peak demands and
generating reserves.  The Company pays net capacity charges to the
AEP Power Pool because its peak demand is greater than its internal
generating capacity.  The decrease in capacity charges was
attributed to a decrease in the Company's prior twelve month peak
demand relative to the total peak demand of all AEP Power Pool
members.
    The reduction in other operation expense was mainly due to
cost savings from staff reductions and reduced accruals and
adjustments for incentive compensation and liability insurance.
   Maintenance expense decreased in the third quarter mainly as
a result of an adjustment to the cost of materials used for power
plant repairs.  In the year-to-date period, the decline in
maintenance expense was due to significant costs incurred in 1998
for repair and restoration of distribution service caused by two
severe snowstorms.
   Federal income tax expense attributable to operations increased
primarily due to changes in certain book/tax differences accounted
for on a flow-through basis for rate-making purposes which were
partially offset in the quarter by a decrease in pre-tax operating
income.
   The increase in nonoperating income is primarily due to the
effect of losses in 1998 on certain power marketing and trading
transactions.  These transactions, which are marked-to-market,
represent non-regulated trading activities outside the Company's
traditional marketing area.
FINANCIAL CONDITION
   Total plant and property additions including capital leases for
the first nine months of 1999 were $147 million.
   During the first nine months of 1999, the Company issued one
series of senior unsecured notes of $150 million with a rate of
6.60% due in 2009 and redeemed $87 million principal amount of
first mortgage bonds with interest rates from 7.15% to 8.43%.
Short-term debt increased by $43 million from year-end balances.
In September 1999, the Company received a $25 million cash capital
contribution from its parent which was credited to paid-in capital.
In October 1999 the Company issued $50 million of 7.45% senior
unsecured notes due 2004.
OTHER MATTERS
Virginia Restructuring
   As discussed in Note 2 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, in February 1999 the Virginia
legislature passed comprehensive legislation, which became law in
March  1999, to restructure the electric utility industry.  Under
the restructuring law a transition to choice of electricity
supplier for retail customers will commence on January 1, 2002 and
be completed, subject to a finding by the Virginia State
Corporation Commission (Virginia SCC) that an effective competitive
market exists, on January 1, 2004.
   The law also provides an opportunity for recovery of just and
reasonable net stranded generation costs.  Stranded costs are those
costs above market including generation related regulatory assets
and impaired tangible assets that potentially would not be
recoverable in a competitive market.  The mechanisms in the
Virginia law for stranded cost recovery are: a capping of rates
until as late as July 1, 2007, and the application of a wires
charge upon customers who depart the incumbent utility in favor of
an alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior to
January 1, 2001 and the establishment of a wires charge by the
fourth quarter of 2001.
   Management has concluded that as of September 30, 1999 the
requirements to apply Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation," continue to be met.  The Company's Virginia rates for
generation will continue to be cost-based regulated until the
establishment of capped rates and the wires charge as provided in
the law.  The establishment of capped rates and the wires charge
should enable the Company to determine its ability to recover
stranded costs, a requirement to discontinue application of SFAS
71.
   When the capped rates and the wires charge are established in
Virginia, the application of SFAS 71 will be discontinued for the
Virginia retail jurisdiction portion of the Company's generating
business.  At that time the Company will have to write-off its
generation-related regulatory assets to the extent that they cannot
be recovered under capped rates and wires charges approved by the
Virginia SCC under the provisions of the restructuring law and
record any asset impairments in accordance with SFAS 121,
"Accounting for the Impairment of Long-lived Assets and for Long-lived
 Assets to Be Disposed Of."  An impairment loss would be
recorded to the extent that the cost of impaired assets cannot be
recovered through the transition recovery mechanisms provided by
the law and future market prices.  Absent the determination in the
regulatory process of capped rates, wires charges and other
pertinent information, it is not possible at this time to determine
if any generation related assets are impaired in accordance with
SFAS 121 and if generation related regulatory assets will be
recovered.  The amount of regulatory assets recorded on the books
applicable to the Company's Virginia retail generating business at
September 30, 1999 is estimated to be $60 million before related
tax effects.
   Should it not be possible under the Virginia law to recover all
or a portion of the generation related regulatory assets and/or
tangible generating assets, it could have a material adverse impact
on results of operations and cash flows.  An estimated
determination of whether the Company will experience any asset
impairment loss regarding its Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
generation related regulatory assets and other transition costs
cannot be made until such time as the transition capped rates and
the wires charge are determined under the law; which is not
expected to occur before the fourth quarter of 2000.
COLI Litigation
   As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the deductibility of certain
interest deductions related to American Electric Power's corporate
owned life insurance (COLI) program for taxable years 1991-1996 is
under review by the Internal Revenue Service (IRS).  Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions.  A disallowance of COLI interest deductions through
September 30, 1999 would reduce earnings by approximately $79
million (including interest).  The Company has made no provision
for any possible earnings impact from this matter.
   The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-1998 to avoid
the potential assessment by the IRS of any additional above market
rate interest on the contested amount. These payments to the IRS
are included on the Consolidated Balance Sheets in other property
and investments pending the resolution of this matter.  The Company
is seeking refunds through litigation of all amounts paid plus
interest.
   In order to resolve this issue, the Company filed suit against
the United States in the US District Court for the Southern
District of Ohio in March 1998. A US Tax Court judge recently
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deductions should be disallowed.
Notwithstanding the decision in Winn-Dixie, management believes,
and has been  advised by outside counsel, that it has a meritorious
position and will vigorously pursue its lawsuit.  In the event the
resolutions of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.
Air Quality
   As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the U.S. Environmental
Protection Agency (Federal EPA) issued final rules which require
reductions in nitrogen oxides (NOx) emissions in 22 eastern states,
including the states in which the generating plants of the Company
and its AEP System affiliates are located.  A number of utilities,
including the Company and its AEP System affiliates , filed
petitions seeking a review of the final rules in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court).  The
matter is currently being litigated.
   On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act.  Federal EPA approved portions of the
states' petitions that would impose NOx reduction requirements on
AEP System generating units which are approximately equivalent to
the reductions contemplated by the NOx emission reduction final
rules.  The AEP System companies with generating plants, as well as
other utility companies, filed a petition in the Appeals Court
seeking review of Federal EPA's approval of portions of the
northeastern states' petitions.  In the second quarter of 1999,
three additional northeastern states filed Section 126 petitions
with Federal EPA similar to those originally filed by the eight
northeastern states.
   Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $410 million for
the Company.  Compliance costs cannot be estimated with certainty.
The actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions.  Unless such costs are recovered from customers through
regulated rates, and where generation is being deregulated
unbundled generation transition rates, wires charges and the future
market price of electricity, they will have an adverse effect on
future results of operations, cash flows and possibly financial
condition.
Federal EPA Complaint and Notice of Violation
   On November 3, 1999 the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company made
modifications to generating units at its Philip Sporn Plant over
the course of the past 25 years to extend unit operating lives or
to increase unit generating capacity without a preconstruction
permit in violation of the Clean Air Act.  Federal EPA also issued
a Notice of Violation to the Company alleging violations of the New
Source Review and New Source Performance Standard provisions of the
Clean Air Act at this plant.  A number of unaffiliated utilities
also received Notices of Violation, complaints or administrative
orders.
   Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to assess
compliance with the New Source Review and New Source Performance
Standard provisions of the Clean Air Act.  Under these provisions
of the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting
requirements under the New Source Review program might be triggered
and the plant may be required to install additional pollution
control technology.  This requirement does not apply to activities
such as routine maintenance, replacement of degraded equipment or
failed components, or other repairs needed for the reliable, safe
and efficient operation of the plant.
   In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each separately
threatened to sue the Company under the Clean Air Act to compel
compliance with the New Source Review and New Source Performance
Standard provisions, alleging that modifications occurred at
certain units at the Company's Clinch River Plant, Kanawha River
Plant and Amos Plant.  The State of New York also threatened to sue
five unaffiliated utilities.  In addition, the State of New York
indicated that it may seek to recover, under state law,
compensation for alleged environmental damage caused by excess
emissions of sulfur dioxide and nitrogen oxides.
   Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its defense
of this matter.
   The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997).  Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be  substantial.
   In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates, and where generation is being deregulated, approved
unbundled transition generation rates, wires charges and future
market prices for energy.
Market Risks
   The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates.  The Company's exposure to market risk from the
trading of electricity and related financial derivative
instruments, which are allocated to the Company through the
American Electric Power System Power Pool, has not changed
materially since December 31, 1998.  Market risk represents the
risk of loss that may impact the Company due to adverse changes in
commodity market prices and interest rates.
   The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at September 30, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
   On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date.  In
addition, certain systems may fail to detect that the year 2000 is
a leap year.  Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company, through the AEP
System, is modifying or replacing its computer hardware and
software programs to minimize Y2K-related failures and repair such
failures if they occur.  This includes both information technology
(IT) systems, which are mainframe and client server applications,
and embedded logic (non-IT) systems, such as process controls for
energy production and delivery.  Externally, the problem is being
addressed with entities that interact with the Company, including
suppliers, customers, creditors, financial service organizations
and other parties essential to the Company's operations.  In the
course of the external evaluation, the Company has sought written
assurances from third parties regarding their state of Y2K
readiness and has been meeting with key vendors in this connection.
   Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The AEP System, along with other electric utilities in North
America, has submitted information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reported summary information to the U.S.
Department of Energy (DOE) regarding the Y2K readiness of electric
utilities.  The fourth and final NERC report, dated August 3, 1999
and entitled: Preparing the Electric Power Systems of North America
for Transition to the Year 2000 - A Status Report and Work Plan,
Second Quarter 1999, states that: "Mission-critical component
testing indicates that the transition through critical Y2K dates is
expected to have minimal impact on electric system operations in
North America."  The report also indicates that, "the risk of
electrical outages caused by Y2K appears to be no higher than the
risks we already experience" from incidents such as severe wind,
ice, floods, equipment failures and power shortages during an
extremely hot or cold period.  NERC has classified the AEP System
as a "Y2K Ready" organization with respect to its electric systems.
   AEP participated in an industry-wide NERC-sponsored drill on
April 9, 1999 simulating the partial loss of voice and data
communications.  There were no major problems encountered with
relaying information with the use of backup telecommunications
systems.  AEP and other utilities also participated in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.  The drill gave
electric utilities in North America an opportunity to test how
workers would respond in emergency situations, such as an outage at
a major power plant or loss of the normal communications system.
The drill did not reveal any major problems or issues for AEP.
   Through the Electric Power Research Institute, AEP is
participating in an electric utility industry-wide effort that has
been established to deal with Y2K problems affecting embedded
systems.  The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in
accordance with business risk.  The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy, and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
<PAGE>
   The AEP System has completed the
process of modifying,
replacing, retiring and testing those mission critical and high
priority digital-based systems with problems processing dates in
the Year 2000.

Costs to Address the Company's Year 2000 Issues - Through September
30, 1999, the Company has spent $12 million on the Y2K project and,
estimates spending an additional $2 million to $4 million to
achieve Y2K readiness.  Most Y2K costs are for software
modifications, IT consultants and salaries and are expensed;
however, in certain cases the Company has acquired hardware that
was capitalized.  The Company intends to fund these expenditures
through internal sources.  The Company has benefited from the
sharing of costs with its affiliates in the AEP System.  The cost
of becoming Y2K 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 Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
   Automated power generation, transmission and distribution systems
   Telecommunications systems
   Energy trading systems
   Time-in-use, demand and remote metering systems for commercial
   and industrial customers and
   Work management and billing systems.

   The potential problems related to erroneous processing by, or
failure of, these systems are:
   Power service interruptions to customers
   Interrupted revenue data gathering and collection
   Poor customer relations resulting from delayed billing and
   settlement.

   Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restored.
   In addition, although relationships with third parties, such
as suppliers, customers and other electric utilities, are being
monitored, these third parties nonetheless represent a risk that
cannot be assessed with precision or controlled with certainty.
   Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Y2K-related issues could materially adversely affect the Company.

Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a Y2K contingency plan and
submitted it to the East Central Area Reliability Council (ECAR) as
part of NERC's review of regional and individual electric utility
contingency plans in 1999.  In addition, the Company has
established detailed contingency plans for its business units to
address alternatives if Y2K related failures occur, including an
operating plan which is coordinated with other ECAR member
utilities.  These contingency plans will be refined by the end of
1999.

   The Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place and
include:
   Availability of additional power generation reserves.
   Coal inventory of approximately 45 days of normal usage.
   Identifying critical operational locations, in order to place
   key employees on duty at those locations during the Y2K
   transition.

<PAGE>
<PAGE>
<TABLE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                          Three Months Ended         Nine Months Ended
                                             September 30,              September 30,
                                           1999         1998         1999          1998
                                                         (in thousands)
<S>                                      <C>          <C>          <C>           <C>
OPERATING REVENUES . . . . . . . . . . . $368,946     $361,405     $949,432      $926,067

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   44,416       49,693      139,416       143,533
  Purchased Power. . . . . . . . . . . .   90,272       80,210      204,718       186,829
  Other Operation. . . . . . . . . . . .   46,829       59,478      139,312       150,843
  Maintenance. . . . . . . . . . . . . .   16,693       13,932       49,013        43,128
  Depreciation . . . . . . . . . . . . .   23,723       22,760       70,429        68,454
  Taxes Other Than Federal Income Taxes.   31,558       29,295       92,687        86,921
  Federal Income Taxes . . . . . . . . .   31,977       31,774       69,859        69,716
          TOTAL OPERATING EXPENSES . . .  285,468      287,142      765,434       749,424

OPERATING INCOME . . . . . . . . . . . .   83,478       74,263      183,998       176,643
NONOPERATING LOSS. . . . . . . . . . . .   (1,076)      (2,337)      (1,193)       (1,109)
INCOME BEFORE INTEREST CHARGES . . . . .   82,402       71,926      182,805       175,534
INTEREST CHARGES . . . . . . . . . . . .   18,683       19,635       57,109        58,856
NET INCOME . . . . . . . . . . . . . . .   63,719       52,291      125,696       116,678
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      533          532        1,598         1,598
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 63,186     $ 51,759     $124,098      $115,080



               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended         Nine Months Ended
                                             September 30,              September 30,
                                           1999         1998         1999          1998
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $203,354     $160,171    $186,441       $138,172
NET INCOME . . . . . . . . . . . . . . .   63,719       52,291     125,696        116,678
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   21,999       20,661      65,997         61,983
    Cumulative Preferred Stock . . . . .      437          437       1,312          1,312
  Capital Stock Expense. . . . . . . . .       95           95         286            286

BALANCE AT END OF PERIOD . . . . . . . . $244,542     $191,269    $244,542       $191,269

The common stock of the Company is wholly owned by American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1999            1998
                                                                 (in thousands)
ASSETS
<S>                                                        <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $1,537,121      $1,526,869
  Transmission . . . . . . . . . . . . . . . . . . . .        349,376         339,934
  Distribution . . . . . . . . . . . . . . . . . . . .        987,274         938,283
  General. . . . . . . . . . . . . . . . . . . . . . .        139,565         130,002
  Construction Work in Progress. . . . . . . . . . . .        106,534         118,477
          Total Electric Utility Plant . . . . . . . .      3,119,870       3,053,565
  Accumulated Depreciation . . . . . . . . . . . . . .      1,194,857       1,134,348

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      1,925,013       1,919,217



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         92,441          73,088



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          8,735           7,206
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         88,401          89,522
    Affiliated Companies . . . . . . . . . . . . . . .         29,312          17,966
    Miscellaneous. . . . . . . . . . . . . . . . . . .          8,732          11,989
    Allowance for Uncollectible Accounts . . . . . . .         (3,900)         (2,598)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         21,762          22,140
  Materials and Supplies . . . . . . . . . . . . . . .         39,918          33,263
  Accrued Utility Revenues . . . . . . . . . . . . . .         45,203          40,127
  Energy Marketing and Trading Contracts . . . . . . .         59,865          12,670
  Prepayments and Other Current Assets . . . . . . . .         29,641          29,084

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        327,669         261,369


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        342,000         353,369


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         15,989          74,647


            TOTAL. . . . . . . . . . . . . . . . . . .     $2,703,112      $2,681,690

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1999            1998
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                        <C>             <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  24,000,000 Shares
    Outstanding - 16,410,426 Shares. . . . . . . . . .     $   41,026      $   41,026
  Paid-in Capital. . . . . . . . . . . . . . . . . . .        572,777         572,492
  Retained Earnings. . . . . . . . . . . . . . . . . .        244,542         186,441
          Total Common Shareholder's Equity. . . . . .        858,345         799,959
  Cumulative Preferred Stock - Subject to
    Mandatory Redemption . . . . . . . . . . . . . . .         25,000          25,000
  Long-term Debt . . . . . . . . . . . . . . . . . . .        924,412         959,786

          TOTAL CAPITALIZATION . . . . . . . . . . . .      1,807,757       1,784,745


OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .         44,670          42,176

CURRENT LIABILITIES:
  Short-term Debt. . . . . . . . . . . . . . . . . . .         28,200          52,500
  Accounts Payable - General . . . . . . . . . . . . .         32,603          34,631
  Accounts Payable - Affiliated Companies. . . . . . .         44,054          37,132
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         99,297         141,831
  Interest Accrued . . . . . . . . . . . . . . . . . .         23,139          14,355
  Energy Marketing and Trading Contracts . . . . . . .         57,608          13,682
  Other. . . . . . . . . . . . . . . . . . . . . . . .         33,485          37,197

          TOTAL CURRENT LIABILITIES. . . . . . . . . .        318,386         331,328

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .        442,198         442,100

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .         46,105          48,710

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .         43,996          32,631

CONTINGENCIES (Note 6)

            TOTAL. . . . . . . . . . . . . . . . . . .     $2,703,112      $2,681,690

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                 Nine Months Ended
                                                                    September 30,
                                                                1999            1998
                                                                   (in thousands)
OPERATING ACTIVITIES:
  <S>                                                         <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 125,696      $ 116,678
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . .     70,727         68,617
    Deferred Federal Income Taxes. . . . . . . . . . . . . .      7,854         12,398
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (2,605)        (2,662)
    Deferred Fuel Costs (net). . . . . . . . . . . . . . . .      3,765        (10,169)
    Amortization of Deferred Property Taxes. . . . . . . . .     51,680         48,775
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .     (5,666)       (18,967)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     (6,277)           879
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     (5,076)         1,228
    Accounts Payable . . . . . . . . . . . . . . . . . . . .      4,894        (19,234)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (42,534)       (36,055)
    Interest Accrued . . . . . . . . . . . . . . . . . . . .      8,784         10,029
    Other Current Assets and Current Liabilities . . . . . .     (7,538)        10,114
  Payment of Disputed Tax and Interest Related to COLI . . .     (2,239)       (37,243)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .      2,634         16,799
        Net Cash Flows From Operating Activities . . . . . .    204,099        161,187

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .    (75,933)       (84,178)
  Proceeds from Sale of Property and Other . . . . . . . . .        495          2,546
        Net Cash Flows Used For Investing Activities . . . .    (75,438)       (81,632)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .       -           111,075
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (24,300)       (11,250)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (35,523)      (122,206)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (65,997)       (61,983)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,312)        (1,312)
        Net Cash Flows Used For Financing Activities . . . .   (127,132)       (85,676)

Net Increase (Decrease) in Cash and Cash Equivalents . . . .      1,529         (6,121)
Cash and Cash Equivalents at Beginning of Period . . . . . .      7,206         12,626
Cash and Cash Equivalents at End of Period . . . . . . . . .  $   8,735      $   6,505

Supplemental Disclosure:
  Cash paid for  interest net  of capitalized amounts was  $45,659,000 and $46,014,000
  and for income taxes was $41,866,000 and $27,254,000 in 1999 and 1998, respectively.
  Noncash acquisitions  under capital leases  were $5,573,000 and  $10,029,000 in 1999
  and 1998, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                            SEPTEMBER 30, 1999
                                (UNAUDITED)

1. GENERAL

       The accompanying unaudited consolidated financial statements should
   be read in conjunction with the 1998 Annual Report as incorporated in and
   filed with the Form 10-K.  Certain prior-period amounts have been
   reclassified to conform to current-period presentation.  In the opinion
   of management, the financial statements reflect all normal recurring
   accruals and adjustments which are necessary for a fair presentation of
   the results of operations for interim periods.

2. FINANCING ACTIVITIES

       During the first nine months of 1999 the Company redeemed $20 million
   of 7.45% first mortgage bonds due in 2024, $9 million of 7.60% first
   mortgage bonds due in 2024 and $7 million of 7.75% first mortgage bonds
   due 2023.

       During the first nine months of 1999, the Company decreased
   short-term debt by $24.3 million.

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

3. NEW ACCOUNTING STANDARDS

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

4. RATE MATTERS

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

       On July 9, 1996, the AEP System companies filed an Open Access
   Transmission Tariff conforming with the FERC's pro-forma transmission
   tariff, subject to the resolution of certain pricing issues.  The 1996
   tariff incorporated transmission rates which were the result of a
   settlement of a pending rate case, but which were being collected subject
   to refund from certain customers who opposed the settlement and continued
   to litigate the reasonableness of AEP's transmission rates.  On July 29,
   1999, the FERC issued an order in the litigated rate case which would
   reduce AEP's rates for the affected customers below the settlement rate.
   AEP and certain of the affected customers have sought rehearing of the
   Commission's Order.  The Company made a provision in September 1999 for
   its share of the refund which it anticipates would result if the
   Commission's order is upheld including interest.

5. OHIO RESTRUCTURING LEGISLATION

       The Ohio Electric Restructuring Act of 1999 became law on October 4,
   1999.  The law provides for customer choice of electricity supplier and
   a residential rate reduction of 5% and a freezing of the unbundled
   generation base rates and a freezing of fuel rates beginning on January
   1, 2001.  The law also provides for a five-year transition period to
   transition from cost based rates to market pricing for generation
   services.  It authorizes the Public Utilities Commission of Ohio (PUCO)
   to address certain major transition issues including unbundling of rates
   and the recovery of regulatory assets, stranded plant costs and other
   transition costs.

       Retail electric services that will be competitive are defined in the
   law as electric generation service, aggregation service, and power
   marketing and brokering.  Under the legislation the PUCO is granted broad
   oversight responsibility and is required by the law to promulgate rules
   for competitive retail electric generation service.  The law also gives
   the PUCO authority to approve a transition plan for each electric utility
   company.

       The law provides Ohio electric utilities with an opportunity to
   recover PUCO approved allowable transition costs through unbundled frozen
   generation rates paid through December 31, 2005 by customers who do not
   switch generation suppliers and through a wires charge for customers who
   switch generation suppliers.  Transition costs can include regulatory
   assets, impairments of generating assets and other stranded costs,
   employee severance and retraining costs, consumer education costs and
   other costs.  Recovery of transition costs can, under certain
   circumstances, extend beyond the five-year frozen rate transition period
   but cannot continue beyond December 31, 2010.  The Company must file a
   transition plan with the PUCO by January 3, 2000 and the PUCO is required
   to issue a transition order no later than October 31, 2000.

       The law also provides that the property tax assessment percentage on
   electric generation property be lowered from 100% to 25% of value
   effective January 1, 2001.  Electric utilities will become subject to the
   Ohio Corporate Franchise Tax and municipal income taxes on January 1,
   2002.  The last year for which electric utilities will pay the excise tax
   based on gross receipts is the tax year ending April 30, 2002.  As of May
   1, 2001 electric distribution companies will be subject to an excise tax
   based on kilowatt-hours sold to Ohio customers.  The gross receipts tax
   is paid at the beginning of the tax year, deferred as a prepaid expense
   and amortized to expense during the tax year pursuant to the tax laws
   whereby the payment of the tax results in the privilege to conduct
   business in the year following the payment of the tax.  The change in the
   tax law to impose an excise tax based on kilowatt-hours sold to Ohio
   customers commencing before the expiration of the gross receipts tax
   privilege period will result in a 12 month period when electric utilities
   are recording as an expense both the gross receipts tax and the excise
   tax.  Management intends to seek recovery of the overlap of the gross
   receipts and excise taxes in the Ohio transition plan filing.

       As discussed in Note 2, "Effects of Regulation and the Zimmer
   Phase-in Plan," of the Notes to Consolidated Financial Statements in
   the 1998 Annual Report, the Company defers as regulatory assets and
   liabilities certain expenses and revenues consistent with the
   regulatory process in
   accordance with Statement of Financial Accounting Standards (SFAS) 71,
   "Accounting for the Effects of Certain Types of Regulation."  Management
   has concluded that as of September 30, 1999 the requirements to apply
   SFAS 71 continue to be met since the Company's rates for generation will
   continue to be cost-based regulated until the establishment of unbundled
   frozen generation rates and a wires charge as provided in the law.  The
   establishment of unbundled frozen generation rates and the wires charge
   should enable the Company to determine its ability to recover transition
   costs including regulatory assets and other stranded costs, a requirement
   to discontinue application of SFAS 71.

       When unbundled generation rates and the wires charge are established,
   the application of SFAS 71 will be discontinued for the Ohio retail
   jurisdiction portion of the  generation business.  At that time the
   Company will have to write-off its Ohio jurisdictional generation-related
   regulatory assets to the extent that they cannot be recovered under the
   unbundled frozen generation rates and distribution wires charges approved
   by the PUCO under the provisions of the restructuring law and record any
   asset impairments in accordance with SFAS 121, "Accounting for the
   Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed
   Of."  An impairment loss would be recorded to the extent that the cost
   of generation assets cannot be recovered through the transition recovery
   mechanisms provided by the law and future market prices.  Absent the
   determination in the regulatory process of an unbundled frozen generation
   rate, the wires charge and other pertinent information, it is not
   possible at this time to determine if any of the Company's generating
   assets are impaired in accordance with SFAS 121.  The amount of
   regulatory assets recorded on the books at September 30, 1999 applicable
   to the Ohio retail jurisdictional generating business is $311 million
   before related tax effects.  Recovery of these regulatory assets will be
   sought as a part of the Company's Ohio transition plan filing.

       An estimated determination of whether the Company will experience any
   asset impairment loss regarding its Ohio retail jurisdictional generating
   assets and any loss from a possible inability to recover Ohio generation
   related regulatory assets and other transition costs cannot be made until
   such time as the unbundled frozen generation rates and the wires charge
   are determined through the regulatory process.  Management will seek full
   recovery of generation-related regulatory assets, any stranded costs and
   other transition costs in its transition plan filing.  The PUCO is
   required to complete its regulatory process and issue a transition order
   establishing the transition rates and wires charges by no later than
   October 31, 2000.  Should the PUCO fail to approve transition rates and
   wires charges that are sufficient to recover the Company's
   generation-related regulatory assets, any other stranded costs and
   transition costs, it could have a material adverse effect on results
   of operations, cash flows and financial condition.

6. CONTINGENCIES

   Litigation

       As discussed in Note 3 of the Notes to Consolidated Financial
   Statements in the 1998 Annual Report, the deductibility of certain
   interest deductions related to American Electric Power's corporate owned
   life insurance (COLI) program for taxable years 1991-1996 is under review
   by the Internal Revenue Service (IRS).  Adjustments have been or will be
   proposed by the IRS disallowing COLI interest deductions.  A disallowance
   of COLI interest deductions through September 30, 1999 would reduce
   earnings by approximately $43 million (including interest).  The Company
   has made no provision for any possible earnings impact from this matter.

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

       In order to resolve this issue, the Company filed suit against the
   United States in the United States (U.S.) District Court for the Southern
   District of Ohio in March 1998.  A US Tax Court judge recently decided
   in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's
   COLI interest deductions should be disallowed.  Notwithstanding the
   decision in Winn-Dixie, management believes, and has been  advised by
   outside counsel, that it has a meritorious position and will vigorously
   pursue its lawsuit.  In the event the resolution of this matter is
   unfavorable, it will have a material adverse impact on results of
   operations and cash flows.

   Air Quality

       As discussed in Note 3 of the Notes to Consolidated Financial
   Statements in the 1998 Annual Report, the U.S. Environmental Protection
   Agency (Federal EPA) issued final rules which require reductions in
   nitrogen oxides (NOx) emissions in 22 eastern states, including the
   states in which the generating plants of the Company and its AEP System
   affiliates are located.  A number of utilities, including the Company and
   its AEP System affiliates, filed petitions seeking a review of the final
   rules in the U.S. Court of Appeals for the District of Columbia Circuit
   (Appeals Court).  The matter is currently being litigated.

       On April 30, 1999, Federal EPA took final action with respect to
   petitions filed by eight northeastern states pursuant to Section 126 of
   the Clean Air Act.  Federal EPA approved portions of the states'
   petitions that would impose NOx reduction requirements on AEP System
   generating units which are approximately equivalent to the reductions
   contemplated by the NOx emission reduction final rules.  The AEP System
   companies with generating plants, as well as other utility  companies,
   filed a petition in the Appeals Court seeking review of Federal EPA's
   approval of portions of the northeastern states' petitions.  In the
   second quarter of 1999, three additional northeastern states filed
   Section 126 petitions with Federal EPA similar to those originally filed
   by the eight northeastern states.

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

   Federal EPA Notice of Violation

       On November 3, 1999, Federal EPA issued a Notice of Violation to the
   Company alleging violations of the New Source Review and New Source
   Performance Standard provisions of the Clean Air Act at its Conesville
   Plant.  A number of unaffiliated utilities also received Notices of
   Violation or administrative orders including a Notice of Violation issued
   to The Cincinnati Gas & Electric Company for Beckjord Plant alleging
   violations of the New Source Review provisions of the Clean Air Act.  The
   Company owns a partial interest in Unit 6 at Beckjord Plant.

       Federal EPA's Notice of Violation is based on an investigation by
   Federal EPA to assess compliance with the New Source Review and New
   Source Performance Standard provisions of the Clean Air Act.  Under these
   provisions of the Clean Air Act, if a plant undertakes a major
   modification that directly results in an emissions increase, permitting
   requirements under the New Source Review program might be triggered and
   the plant may be required to install additional pollution control
   technology.  This requirement does not apply to activities such as
   routine maintenance, replacement of degraded equipment or failed
   components, or other repairs needed for the reliable, safe and efficient
   operation of the plant.

       Management believes its maintenance, repair and replacement
   activities were in conformity with the Clean Air Act and were exempted
   from the New Source Review and New Source Performance Standard
   requirements, and intends to vigorously pursue its defense of this
   matter.

       The Clean Air Act authorizes civil penalties of up to $27,500 per day
   per violation at each generating unit ($25,000 per day prior to January
   30, 1997).  Civil penalties, if ultimately imposed, and the cost of any
   required new pollution control equipment, if all of Federal EPA's
   contentions are upheld, could be  substantial.

       In the event the Company does not prevail, any capital and operating
   costs of additional pollution control equipment that may be required as
   well as any penalties imposed would adversely affect future results of
   operations, cash flows and possibly financial condition unless such costs
   can be recovered through PUCO approved unbundled generation transition
   rates, wires charges and the future market price for electricity.

   Other

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

<PAGE>
<PAGE>
             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
         MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
                 THIRD QUARTER 1999 vs. THIRD QUARTER 1998
                                    AND
                  YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
   Net income increased $11.4 million or 22% for the third quarter and $9
million or 8% for the year-to-date period primarily due to increased sales to
retail customers reflecting customer growth and in the year-to-date period
colder winter weather.
   Income statement line items which changed significantly were:
                                    Increase (Decrease)
                             Third Quarter        Year-to-Date
                           (in millions)   %   (in millions)   %

Operating Revenues. . . . .    $  7.5      2       $ 23.4      3
Fuel Expense. . . . . . . .      (5.3)   (11)        (4.1)    (3)
Purchased Power Expense . .      10.1     13         17.9     10
Other Operation Expense . .     (12.6)   (21)       (11.5)    (8)
Maintenance Expense . . . .       2.8     20          5.9     14

   Operating revenues increased in both the third quarter and the
 year-to-date period due predominantly to increased retail sales.
The increase in retail revenues resulted from increased sales to
residential and commercial
customers reflecting growth in the number of customers and in the
year-to-date period colder winter weather.  Revenues from wholesale customers
declined, due to a decline in wholesale margins, partially offsetting the
retail revenue gains.
   The decrease in fuel expense was due to a decline in generation
reflecting a decrease in availability of certain generating units in 1999 due
to power plant maintenance outages.
   The increase in purchased power expense in the third quarter was
primarily the result of increased purchases of electricity from the American
Electric Power (AEP) System Power Pool (AEP Power Pool) and unaffiliated
companies to replace unavailable generation and to meet the increase in
demand from retail customers.  In the year-to-date period, increased capacity
charges from the AEP Power Pool were the primary reason for the increase in
purchased power expense.  Under the terms of the AEP Power Pool, capacity
credits and charges are designed to allocate the cost of the AEP System's
capacity among the AEP Power Pool members based on their relative peak
demands and generating reserves.  The Company pays net capacity charges to
the AEP Power Pool because its peak demand is greater than its internal
generating capacity.  The increase in capacity charge was attributed to an
increase in the Company's prior twelve month peak demand relative to the
total peak demand of all AEP Power Pool members.
   The reduction in other operation expense was mainly due to cost savings
from staffing reductions, a reduction in bad debt expense, reduced accruals
and adjustments for incentive compensation and liability insurance, and a
gain on the sale of excess emission allowances.
   Maintenance expense increased due to tree trimming for overhead
distribution lines and scheduled power plant maintenance outages in 1999.
The cost of plant maintenance outages was mitigated by cost savings from
planned staffing reductions.

<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,
                                           1999        1998           1999         1998
                                                         (in thousands)
<S>                                      <C>         <C>           <C>         <C>
OPERATING REVENUES . . . . . . . . . . . $411,248    $412,908      $1,081,914  $1,089,647

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   51,908      51,014         135,831     133,768
  Purchased Power. . . . . . . . . . . .   93,683      92,728         223,508     237,391
  Other Operation. . . . . . . . . . . .  139,997      97,985         346,830     257,268
  Maintenance. . . . . . . . . . . . . .   43,526      39,107          99,349      99,444
  Depreciation and Amortization. . . . .   37,626      36,380         112,106     108,407
  Taxes Other Than Federal Income Taxes.   12,356      16,514          48,641      49,011
  Federal Income Taxes . . . . . . . . .    6,067      20,541          23,760      52,157
          TOTAL OPERATING EXPENSES . . .  385,163     354,269         990,025     937,446
OPERATING INCOME . . . . . . . . . . . .   26,085      58,639          91,889     152,201
NONOPERATING INCOME (LOSS) . . . . . . .    2,407      (2,404)          5,698         191
INCOME BEFORE INTEREST CHARGES . . . . .   28,492      56,235          97,587     152,392
INTEREST CHARGES . . . . . . . . . . . .   20,408      17,544          59,688      51,421
NET INCOME . . . . . . . . . . . . . . .    8,084      38,691          37,899     100,971
PREFERRED STOCK DIVIDEND REQUIREMENTS. .    1,218       1,208           3,647       3,627
EARNINGS APPLICABLE TO COMMON STOCK. . . $  6,866    $ 37,483      $   34,252  $   97,344



               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended          Nine Months Ended
                                             September 30,              September 30,
                                           1999        1998           1999        1998
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $223,212    $279,943       $253,154    $278,814
NET INCOME . . . . . . . . . . . . . . .    8,084      38,691         37,899     100,971
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   28,664      29,366         85,992      88,098
    Cumulative Preferred Stock . . . . .    1,182       1,183          3,546       3,550
  Capital Stock Expense. . . . . . . . .       65          25            130          77

BALANCE AT END OF PERIOD . . . . . . . . $201,385    $288,060       $201,385    $288,060

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

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1999            1998
                                                                 (in thousands)
ASSETS
<S>                                                        <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,586,427      $2,565,041
  Transmission . . . . . . . . . . . . . . . . . . . .        924,028         913,495
  Distribution . . . . . . . . . . . . . . . . . . . .        791,768         768,888
  General (including nuclear fuel) . . . . . . . . . .        233,394         228,013
  Construction Work in Progress. . . . . . . . . . . .        183,358         156,411
          Total Electric Utility Plant . . . . . . . .      4,718,975       4,631,848
  Accumulated Depreciation and Amortization. . . . . .      2,175,163       2,081,355

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,543,812       2,550,493

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
 DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . . . .        693,532         648,307

OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        207,141         197,368



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         19,784          12,465
  Accounts Receivable (net). . . . . . . . . . . . . .        131,878         130,746
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         25,551          20,857
  Materials and Supplies . . . . . . . . . . . . . . .         83,515          78,009
  Accrued Utility Revenues . . . . . . . . . . . . . .         43,045          37,277
  Energy Marketing and Trading Contracts . . . . . . .         65,076          14,105
  Prepayments. . . . . . . . . . . . . . . . . . . . .          6,403           4,848

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        375,252         298,307




REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        566,226         421,475

DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         17,602          32,573



            TOTAL. . . . . . . . . . . . . . . . . . .     $4,403,565      $4,148,523

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                         September 30,    December 31,
                                                              1999            1998
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                       <C>              <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  2,500,000 Shares
    Outstanding - 1,400,000 Shares . . . . . . . . . .    $   56,584       $   56,584
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       732,711          732,605
  Retained Earnings. . . . . . . . . . . . . . . . . .       201,385          253,154
          Total Common Shareholder's Equity. . . . . .       990,680        1,042,343
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .         9,255            9,273
    Subject to Mandatory Redemption. . . . . . . . . .        67,445           68,445
  Long-term Debt . . . . . . . . . . . . . . . . . . .     1,123,841        1,140,789

          TOTAL CAPITALIZATION . . . . . . . . . . . .     2,191,221        2,260,850

OTHER NONCURRENT LIABILITIES:
  Nuclear Decommissioning. . . . . . . . . . . . . . .       488,931          445,934
  Other. . . . . . . . . . . . . . . . . . . . . . . .       247,620          240,320

          TOTAL OTHER NONCURRENT LIABILITIES . . . . .       736,551          686,254

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .       133,000           35,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .       190,850          108,700
  Accounts Payable - General . . . . . . . . . . . . .        50,019           53,187
  Accounts Payable - Affiliated Companies. . . . . . .        10,808           37,647
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .        30,510           35,161
  Interest Accrued . . . . . . . . . . . . . . . . . .        17,808           15,279
  Rent Accrued - Rockport Plant Unit 2 . . . . . . . .        23,427            4,963
  Obligations Under Capital Leases . . . . . . . . . .        11,047            9,667
  Energy Marketing and Trading Contracts . . . . . . .        62,624           15,228
  Other. . . . . . . . . . . . . . . . . . . . . . . .        88,700           67,102

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       618,793          381,934

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       603,133          559,288

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       124,085          129,779

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .        85,932           88,712

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        43,850           41,706

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .    $4,403,565       $4,148,523

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                 Nine Months Ended
                                                                    September 30,
                                                                 1999           1998
                                                                   (in thousands)

OPERATING ACTIVITIES:
  <S>                                                         <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $  37,899      $ 100,971
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    115,014        111,510
    Amortization of Incremental Nuclear Refueling
      Outage Expenses (net). . . . . . . . . . . . . . . . .      6,413         11,368
    Under-recovery of Fuel and Purchased Power . . . . . . .    (82,213)       (42,676)
    Deferred Nuclear Outage Costs (net). . . . . . . . . . .    (90,000)          -
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     57,254         11,226
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (5,694)        (5,727)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .     (1,132)       (33,328)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    (10,200)          (308)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     (5,768)        (9,857)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (30,007)        10,617
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .     18,464         18,464
  Payment of Disputed Taxes and Interest Related to COLI . .     (3,228)       (53,628)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     30,208         21,002
        Net Cash Flows From Operating Activities . . . . . .     37,010        139,634

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .    (97,044)       (98,218)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .      1,904          4,154
        Net Cash Flows Used For Investing Activities . . . .    (95,140)       (94,064)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    148,379        122,222
  Retirement of Cumulative Preferred Stock . . . . . . . . .     (1,042)           (65)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (74,500)       (55,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .     82,150        (16,100)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (85,992)       (88,098)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (3,546)        (3,551)
        Net Cash Flows From (Used For) Financing Activities.     65,449        (40,592)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .      7,319          4,978
Cash and Cash Equivalents at Beginning of Period . . . . . .     12,465          5,860
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  19,784      $  10,838

Supplemental Disclosure:
  Cash  paid (received) for interest net of  capitalized  amounts was  $54,928,000 and
  $49,041,000 and for income taxes was $(29,106,000) and $20,224,000 in 1999 and 1998,
  respectively.   Noncash  acquisitions  under  capital  leases  were  $9,005,000  and
  $7,050,000 in 1999 and 1998, respectively.

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
         INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        SEPTEMBER 30, 1999
                           (UNAUDITED)

1.  GENERAL

       The accompanying unaudited consolidated financial
   statements should be read in conjunction with the 1998 Annual
   Report as incorporated in and filed with the Form 10-K.
   Certain prior-period amounts have been reclassified to conform
   to current-period presentation.  In the opinion of management,
   the financial statements reflect all normal recurring accruals
   and adjustments which are necessary for a fair presentation of
   the results of operations for interim periods.

2. FINANCING ACTIVITIES

       In July 1999 the Company issued $150 million of 6.875%
   senior unsecured notes due 2004.  During the first nine months
   of 1999, the Company reacquired the following first mortgage
   bonds:
                                        Principal
                                        Amount
       % Rate      Due Date         Reacquired
                                      (in thousands)
       6.80        July 1, 2003     $20,000
       6.55        October 1, 2003       20,000
       6.55        March 1, 2004         25,000
       7.20        February 1, 2024  10,000

       During the first nine months of 1999, the Company increased
   short-term debt by $82 million.

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

3. NEW ACCOUNTING STANDARDS

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

4. RATE MATTERS

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

       On July 9, 1996, the AEP System companies filed an Open
   Access Transmission Tariff conforming with the FERC's pro-forma
   transmission tariff, subject to the resolution of certain
   pricing issues.  The 1996 tariff incorporated transmission
   rates which were the result of a settlement of a pending rate
   case, but which were being collected subject to refund from
   certain customers who opposed the settlement and continued to
   litigate the reasonableness of AEP's transmission rates.  On
   July 29, 1999, the FERC issued an order in the litigated rate
   case which would reduce AEP's rates for the affected customers
   below the settlement rate.  AEP and certain of the affected
   customers have sought rehearing of the Commission's Order.  The
   Company made a provision in September 1999 for its share of the
   refund which it anticipates would result if the Commission's
   order is upheld including interest.

5. CONTINGENCIES

   Litigation

       As discussed in Note 3 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the
   deductibility of certain interest deductions related to
   American Electric Power's corporate owned life insurance (COLI)
   program for taxable years 1991-1996 is under review by the
   Internal Revenue Service (IRS).  Adjustments have been or will
   be proposed by the IRS disallowing COLI interest deductions.
   A disallowance of COLI interest deductions through September
   30, 1999 would reduce earnings by approximately $66 million
   (including interest).  The Company has made no provision for
   any possible earnings impact from this matter.

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

       In order to resolve this issue, the Company filed suit
   against the United States in the U.S. District Court for the
   Southern District of Ohio in March 1998. A US Tax Court judge
   recently decided in the Winn-Dixie Stores v. Commissioner case
   that a corporate taxpayer's COLI interest deductions should be
   disallowed.  Notwithstanding the decision in Winn-Dixie,
   management believes, and has been  advised by outside counsel,
   that it has a meritorious position and will vigorously pursue
   its lawsuit.  In the event the resolution of this matter is
   unfavorable, it will have a material adverse impact on results
   of operations and cash flows.

   Air Quality

       As discussed in Note 3 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the U.S.
   Environmental Protection Agency (Federal EPA) issued final
   rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which
   the generating plants of the Company and its AEP System
   affiliates are located.  A number of utilities, including the
   Company and its AEP System affiliates, filed petitions seeking
   a review of the final rules in the U.S. Court of Appeals for
   the District of Columbia Circuit (Appeals Court).  The matter
   is currently being litigated.

       On April 30, 1999, Federal EPA took final action with
   respect to petitions filed by eight northeastern states
   pursuant to Section 126 of the Clean Air Act.  Federal EPA
   approved portions of the states' petitions that would impose
   NOx reduction requirements on AEP System generating units which
   are approximately equivalent to the reductions contemplated by
   the NOx emission reduction final rules.  The AEP System
   companies with generating plants, as well as other utility
   companies, filed a petition in the Appeals Court seeking review
   of Federal EPA's approval of portions of the northeastern
   states' petitions.  In the second quarter of 1999, three
   additional northeastern states filed Section 126 petitions with
   Federal EPA similar to those originally filed by the eight
   northeastern states.

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

   Federal EPA Complaint and Notice of Violation

       On November 3, 1999 the Department of Justice, at the
   request of Federal EPA, filed a complaint in the U.S. District
   Court for the Southern District of Ohio that alleges the
   Company made modifications to generating units at its Tanners
   Creek Plant over the course of the past 25 years to extend unit
   operating lives or to increase unit generating capacity without
   a preconstruction permit in violation of the Clean Air Act.
   Federal EPA also issued a Notice of Violation to the Company
   alleging violations of the New Source Review and New Source
   Performance Standard provisions of the Clean Air Act at this
   plant.  A number of unaffiliated utilities also received
   Notices of Violation, complaints or administrative orders.

       Federal EPA's Notice of Violation and the government's
   complaint are based on an investigation by Federal EPA to
   assess compliance with the New Source Review and New Source
   Performance Standard provisions of the Clean Air Act.  Under
   these provisions of the Clean Air Act, if a plant undertakes
   a major modification that directly results in an emissions
   increase, permitting requirements under the New Source Review
   program might be triggered and the plant may be required to
   install additional pollution control technology.  This
   requirement does not apply to activities such as routine
   maintenance, replacement of degraded equipment or failed
   components, or other repairs needed for the reliable, safe and
   efficient operation of the plant.

       In the fall of 1999 the State of New York, various
   environmental groups and the State of Connecticut each
   separately threatened to sue the Company under the Clean Air
   Act to compel compliance with the New Source Review and New
   Source Performance Standard provisions, alleging that
   modifications occurred at certain units at the Company's
   Tanners Creek Plant.  The State of New York also threatened to
   sue five unaffiliated utilities.  In addition, the State of New
   York indicated that it may seek to recover, under state law,
   compensation for alleged environmental damage caused by excess
   emissions of sulfur dioxide and nitrogen oxides.

       Management believes its maintenance, repair and replacement
   activities were in conformity with the Clean Air Act and were
   exempted from the New Source Review and New Source Performance
   Standard requirements, and intends to vigorously pursue its
   defense of this matter.

       The Clean Air Act authorizes civil penalties of up to
   $27,500 per day per violation at each generating unit ($25,000
   per day prior to January 30, 1997).  Civil penalties, if
   ultimately imposed by the court, and the cost of any required
   new pollution control equipment, if the court accepts all of
   Federal EPA's contentions, could be  substantial.

       In the event the Company does not prevail, any capital and
   operating costs of additional pollution control equipment that
   may be required as well as any penalties imposed would
   adversely affect future results of operations, cash flows and
   possibly financial condition unless such costs can be recovered
   through regulated rates and/or reflected in the future market
   prices of electricity if generation is deregulated.

   Cook Plant Shutdown

       As discussed in Note 3 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, both units of
   the Cook Plant were shut down in September 1997 due to
   questions regarding the operability of certain safety systems
   that arose during a Nuclear Regulatory Commission (NRC)
   architect engineer design inspection.  The NRC issued a
   Confirmatory Action Letter in September 1997 requiring the
   Company to address certain issues identified in the letter.
   In 1998 the NRC notified the Company that it had convened a
   Restart Panel for Cook Plant and provided a list of required
   restart activities.  In order to identify and resolve all
   issues, including those in the letter, necessary to restart the
   Cook units, the Company is working with the NRC and will be
   meeting with the Panel on a regular basis, until the units are
   returned to service.

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

       The Company's plan to restart the Cook Plant units has Unit
   2 scheduled to return to service in April 2000 and Unit 1 to
   return to service in September 2000.  The restart plan was
   developed based upon a comprehensive systems readiness review
   of all operating systems at the Cook Plant.  When maintenance
   and other activities required for restart are complete, the
   Company will seek concurrence from the NRC to return the Cook
   Plant to service.

       Management intends to replace the steam generator for Unit
   1 before the unit is returned to service.  Costs associated
   with the steam generator replacement are estimated to be
   approximately $165 million, which will be accounted for as a
   capital investment unrelated to the restart.  At September 30,
   1999, $82 million has been spent on the steam generator
   replacement.

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

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

       In June 1999 the Company announced that a settlement
   agreement for two open Michigan power supply cost recovery
   reconciliation cases had been reached with the staff of the
   Michigan Public Service Commission (MPSC).  The proposed
   settlement agreement would limit the Company's ability to
   increase base rates and freeze power supply costs for five
   years, allow for the amortization of deferred power supply cost
   for 1997, 1998 and 1999 over five years, allow for the deferral
   and amortization of non-fuel nuclear operation and maintenance
   expenses over five years and resolve all issues related to the
   Cook Plant extended restart outage. The pending Michigan
   settlement limits deferrals to $50 million of 1999
   jurisdictional non-fuel nuclear operation and maintenance
   costs. Hearings have been held to give the one intervenor who
   opposed the approval of the settlement agreement the
   opportunity to voice its objections.  The settlement agreement
   is pending before the MPSC.

       Expenditures for the restart of the Cook units are
   estimated to total approximately $574 million and will be
   accounted for primarily as a current period operation and
   maintenance expense in 1999 and 2000.  Through September 30,
   1999, $280 million has been spent, of which $196 million was
   incurred in 1999.  Pursuant to the Indiana settlement agreement
   $112.5 million of incremental operation and maintenance costs
   were deferred for the nine months ended September 30, 1999.
   The Indiana jurisdiction deferral is limited to up to $150
   million of incremental restart costs incurred in 1999.  The
   amortization of such costs through September 30, 1999 was $22.5
   million.  At September 30, 1999, the unamortized balance of
   incremental restart related operation and maintenance costs was
   $90 million and was included in regulatory assets.  Also
   deferred as a regulatory asset at September 30, 1999 was $148
   million of replacement energy fuel costs.

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

   Other

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

<PAGE>
<PAGE>
         INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                     AND FINANCIAL CONDITION
            THIRD QUARTER 1999 vs. THIRD QUARTER 1998
                               AND
             YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
   Net income decreased $30.6 million or 79% for the quarter and
$63.1 million or 62% for the year-to-date period due primarily to
an increase in the cost of the extended Cook Nuclear Plant restart
outage.
   Income statement line items which changed significantly were:
                                    Increase (Decrease)
                             Third Quarter         Year-to-Date
                          (in millions)   %     (in millions)  %

Operating Revenues . . . .   $ (1.6)      -       $  (7.7)    (1)
Purchased Power Expense. .      1.0       1         (13.9)    (6)
Other Operation Expense. .     41.9      43          89.6     35
Maintenance Expense. . . .      4.4      11          (0.1)     -
Taxes Other Than Federal
 Income Taxes. . . . . . .     (4.2)    (25)         (0.4)     -
Federal Income Taxes . . .    (14.5)    (70)        (28.4)   (54)
Nonoperating Income. . . .      4.8     200           5.5    N.M.
Interest Charges . . . . .      2.9      16           8.3     16

N.M. = Not Meaningful

   Operating revenues declined as a decrease in wholesale revenues
was largely offset by an increase in retail revenues.  The decrease
in wholesale revenues resulted from a decline in wholesale power
sales margins.  Retail revenues rose due to increased sales of 7%
in the quarter and 5% in the year-to-date period.  The retail sales
increase can be attributed to increased energy usage by residential
and commercial customers due to colder winter weather and warmer
summer temperatures.  In the year-to-date period, the rise in
retail revenues from increased sales was mostly offset by the
effect of an Indiana settlement agreement that allowed amortization
of unrecovered fuel cost revenues over five years.  Under the terms
of the settlement agreement, approved by the Indiana commission in
March 1999, the fuel recovery rate was reduced and fixed through
March 1, 2004.
<PAGE>
   The decrease in purchased power expense in the year-to-date
period was due to a reduction in the average price of purchased
power as the Company was able to substitute lower cost purchases
from affiliates for more expensive power bought from unaffiliated
utilities.
   Other operation and maintenance expense increased primarily as
a result of costs associated with the extended Cook Plant restart
outage including nuclear engineering and contract employee costs.
   The decrease in taxes other than federal income taxes in the
third quarter is due primarily to a favorable accrual adjustment
for Indiana supplemental income tax to reflect a revised taxable
income estimate.
   Federal income taxes attributable to operations decreased
significantly in both periods as a result of a decrease in pre-tax
operating income.
   The increase in nonoperating income is primarily due to losses
on certain power marketing and trading transactions in 1998.  These
transactions, which are marked-to-market, represent non-regulated
trading activities outside the AEP System Power Pool's traditional
marketing area.
   Interest charges increased due to increased long-term and
short-term borrowing to fund the expenditures for the Cook Plant
restart effort.
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 1999 short-term debt
outstanding increased by $82 million.  The short-term debt
limitation of the Company was increased from $300 million to $500
million with approval of the Securities and Exchange Commission.
   During the first nine months of 1999 the Company redeemed $75
million principal amount of first mortgage bonds with interest
rates from 6.55% to 7.20% and issued $150 million of 6.875% senior
unsecured notes due 2004.

<PAGE>
OTHER MATTERS
Spent Nuclear Fuel (SNF) Litigation
   As discussed in Management's Discussion and Analysis of Results
of Operations and Financial Condition (MDA) in the 1998 Annual
Report, as a result of the Department of Energy's (DOE) failure to
make sufficient progress toward a permanent repository or otherwise
assume responsibility for SNF, the Company along with a number of
unaffiliated utilities and states filed suit in the United States
(U.S.) Court of Appeals for the District of Columbia Circuit
requesting, among other things, that the court order DOE to meet
its obligations under the law.  The court ordered the parties to
proceed with contractual remedies but declined to order DOE to
begin accepting SNF for disposal.  DOE estimates its planned site
for the nuclear waste will not be ready until at least 2010.  In
June 1998, the Company filed a complaint in the U.S. Court of
Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual
deadline to begin disposing of SNF generated by the Cook Plant.
Similar lawsuits have been filed by other utilities.  On April 6,
1999, the court granted DOE's motion to dismiss a lawsuit filed by
another utility.  On May 20, 1999, the other utility appealed this
decision to the U.S. Court of Appeals for the Federal Circuit.
I&M's case has been stayed pending final resolution of the other
utility's appeal.
Cook Plant Shutdown
   As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, both units of the Cook Plant
were shut down in September 1997 due to questions regarding the
operability of certain safety systems that arose during a Nuclear
Regulatory Commission (NRC) architect engineer design inspection.
The NRC issued a Confirmatory Action Letter in September 1997
requiring the Company to address certain issues identified in the
letter.  In 1998 the NRC notified the Company that it had convened
a Restart Panel for Cook Plant and provided a list of required
restart activities.  In order to identify and resolve all issues,
including those in the letter, necessary to restart the Cook units,
the Company is working with the NRC and will be meeting with the
Panel on a regular basis, until the units are returned to service.
   In May 1999 the Company received a letter from the NRC
indicating that NRC senior managers had identified Cook Plant as an
"agency-focus plant."  The NRC senior managers concluded that
continued agency-level oversight was appropriate; however, the NRC
required no additional action to redirect Cook Plant activities.
The letter states that the NRC staff will continue to monitor Cook
Plant performance through the Restart Panel process and evaluate
whether additional action may be necessary.
   The Company's plan to restart the Cook Plant units has Unit 2
scheduled to return to service in April 2000 and Unit 1 to return
to service in September 2000.  The restart plan was developed based
upon a comprehensive systems readiness review of all operating
systems at the Cook Plant.  When maintenance and other activities
required for restart are complete, the Company will seek
concurrence from the NRC to return the Cook Plant to service.
   Management intends to replace the steam generator for Unit 1
before the unit is returned to service.  Costs associated with the
steam generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart.  At September 30, 1999, $82 million has
been spent on the steam generator replacement.
   The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal-based purchased power is being
substituted for the unavailable low cost nuclear generation.
Actual replacement energy fuel costs that exceeded the costs
reflected in billings have been recorded as a regulatory asset
under the Indiana and Michigan retail jurisdictional fuel cost
recovery mechanisms.
   On March 30, 1999 the Indiana Utility Regulatory Commission
(IURC) approved a settlement agreement that resolves all matters
related to the recovery of replacement energy fuel costs and all
outage/restart issues during the extended outage of the Cook Plant.
The settlement agreement provides for, among other things, a
billing credit of $55 million, including interest, to Indiana
retail customers' bills; the deferral of unrecovered fuel revenues
accrued between September 9, 1997 and December 31, 1999, including
a $52.3 million revenue portion of the $55 million billing credit;
the deferral of up to $150 million of incremental operation and
maintenance costs in 1999 for Cook Plant above the amount included
in base rates; the amortization of the deferred fuel and non-fuel
operation and maintenance cost deferrals over a five-year period
ending December 31, 2003; a freeze in base rates through December
31, 2003; and a fixed fuel recovery charge through March 1, 2004.
The $55 million credit was applied to retail customers' bills
during the months of July, August and September 1999.
   In June 1999 the Company announced that a settlement agreement
for two open Michigan power supply cost recovery reconciliation
cases had been reached with the staff of the Michigan Public
Service Commission (MPSC).  The proposed settlement agreement would
limit the Company's ability to increase base rates and freeze power
supply costs for five years, allow for the amortization of deferred
power supply cost for 1997, 1998 and 1999 over five years, allow
for the deferral and amortization of non-fuel nuclear operation and
maintenance expenses over five years and resolve all issues related
to the Cook Plant extended restart outage. The pending Michigan
settlement limits deferrals to $50 million of 1999 jurisdictional
non-fuel nuclear operation and maintenance costs. Hearings have
been held to give the one intervenor who opposed the approval of
the settlement agreement the opportunity to voice its objections.
The settlement agreement is pending before the MPSC.
   Expenditures for the restart of the Cook units are estimated
to total approximately $574 million and will be accounted for
primarily as a current period operation and maintenance expense in
1999 and 2000.  Through September 30, 1999, $280 million has been
spent, of which $196 million was incurred in 1999.  Pursuant to the
Indiana settlement agreement $112.5 million of incremental
operation and maintenance costs were deferred for the nine months
ended September 30, 1999.  The Indiana jurisdiction deferral is
limited to up to $150 million of incremental restart costs incurred
in 1999.  The amortization of such costs through September 30, 1999
was $22.5 million.  At September 30, 1999, the unamortized balance
of incremental restart related operation and maintenance costs was
$90 million and was included in regulatory assets.  Also deferred
as a regulatory asset at September 30, 1999 was $148 million of
replacement energy fuel costs.
   The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations, cash
flows, and possibly financial condition through 2003.  Management
believes that the Cook units will be successfully returned to
service by April and September 2000, however, if for some unknown
reason the units are not returned to service or their return is
delayed significantly it would have an even greater adverse effect
on future results of operations, cash flows and financial
condition.
COLI Litigation
   As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the deductibility of certain
interest deductions related to American Electric Power's corporate
owned life insurance (COLI) program for taxable years 1991-1996 is
under review by the Internal Revenue Service (IRS).  Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions.  A disallowance of COLI interest deductions through
September 30, 1999 would reduce earnings by approximately $66
million (including interest).  The Company has made no provision
for any possible earnings impact from this matter.
   The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-1998 to avoid
the potential assessment by the IRS of any additional above market
rate interest on the contested amount. These payments to the IRS
are included on the Consolidated Balance Sheets in other property
and investments pending the resolution of this matter.  The Company
is seeking refunds through litigation of all amounts paid plus
interest.
   In order to resolve this issue, the Company filed suit against
the United States in the U.S. District Court for the Southern
District of Ohio in March 1998. A US Tax Court judge recently
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deductions should be disallowed.
Notwithstanding the decision in Winn-Dixie, management believes,
and has been  advised by outside counsel, that it has a meritorious
position and will vigorously pursue its lawsuit.  In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.
Air Quality
   As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the U.S. Environmental
Protection Agency (Federal EPA) issued final rules which require
reductions in nitrogen oxides (NOx) emissions in 22 eastern states,
including the states in which the generating plants of the Company
and its AEP System affiliates are located.  A number of utilities,
including the Company and its AEP System affiliates, filed
petitions seeking a review of the final rules in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court).  The
matter is currently being litigated.
   On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act.  Federal EPA approved portions of the
states' petitions that would impose NOx reduction requirements on
AEP System generating units which are approximately equivalent to
the reductions contemplated by the NOx emission reduction final
rules.  The AEP System companies with generating plants, as well as
other utility companies, filed a petition in the Appeals Court
seeking review of Federal EPA's approval of portions of the
northeastern states' petitions.  In the second quarter of 1999,
three additional northeastern states filed Section 126 petitions
with Federal EPA similar to those originally filed by the eight
northeastern states.
   Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $215 million for
the Company.  Compliance costs cannot be estimated with certainty.
The actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions.  Unless such costs are recovered from customers through
regulated rates and/or reflected in the future market price of
electricity if generation is deregulated, they will have an adverse
effect on future results of operations, cash flows and possibly
financial condition.
Federal EPA Complaint and Notice of Violation
   On November 3, 1999 the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company made
modifications to generating units at its Tanners Creek Plant over
the course of the past 25 years to extend unit operating lives or
to increase unit generating capacity without a preconstruction
permit in violation of the Clean Air Act.  Federal EPA also issued
a Notice of Violation to the Company alleging violations of the New
Source Review and New Source Performance Standard provisions of the
Clean Air Act at this plant.  A number of unaffiliated utilities
also received Notices of Violation, complaints or administrative
orders.
   Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to assess
compliance with the New Source Review and New Source Performance
Standard provisions of the Clean Air Act.  Under these provisions
of the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting
requirements under the New Source Review program might be triggered
and the plant may be required to install additional pollution
control technology.  This requirement does not apply to activities
such as routine maintenance, replacement of degraded equipment or
failed components, or other repairs needed for the reliable, safe
and efficient operation of the plant.
   In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each separately
threatened to sue the Company under the Clean Air Act to compel
compliance with the New Source Review and New Source Performance
Standard provisions, alleging that modifications occurred at
certain units at the Company's Tanners Creek Plant.  The State of
New York also threatened to sue five unaffiliated utilities.  In
addition, the State of New York indicated that it may seek to
recover, under state law, compensation for alleged environmental
damage caused by excess emissions of sulfur dioxide and nitrogen
oxides.
   Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its defense
of this matter.
   The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997).  Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be  substantial.
   In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates and/or reflected in the future market prices of electricity
if generation is deregulated.
Market Risks
   The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates.  The Company's exposure to market risk from the
trading of electricity and related financial derivative instruments
has not changed materially since December 31, 1998.  Market risk
represents the risk of loss that may impact the Company due to
adverse changes in commodity market prices and interest rates.
   The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at September 30, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
   On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date.  In
addition, certain systems may fail to detect that the year 2000 is
a leap year.  Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company, through the AEP
System, is modifying or replacing its computer hardware and
software programs to minimize Y2K-related failures and repair such
failures if they occur.  This includes both information technology
(IT) systems, which are mainframe and client server applications,
and embedded logic (non-IT) systems, such as process controls for
energy production and delivery.  Externally, the problem is being
addressed with entities that interact with the Company, including
suppliers, customers, creditors, financial service organizations
and other parties essential to the Company's operations.  In the
course of the external evaluation, the Company has sought written
assurances from third parties regarding their state of Y2K
readiness and has been meeting with key vendors in this connection.
   Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The AEP System, along with other electric utilities in North
America, has submitted information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reported summary information to the U.S.
Department of Energy (DOE) regarding the Y2K readiness of electric
utilities.  The fourth and final NERC report, dated August 3, 1999
and entitled: Preparing the Electric Power Systems of North America
for Transition to the Year 2000 - A Status Report and Work Plan,
Second Quarter 1999, states that: "Mission-critical component
testing indicates that the transition through critical Y2K dates is
expected to have minimal impact on electric system operations in
North America."  The report also indicates that, "the risk of
electrical outages caused by Y2K appears to be no higher than the
risks we already experience" from incidents such as severe wind,
ice, floods, equipment failures and power shortages during an
extremely hot or cold period.  NERC has classified the AEP System
as a "Y2K Ready" organization with respect to its electric systems.
   AEP participated in an industry-wide NERC-sponsored drill on
April 9, 1999 simulating the partial loss of voice and data
communications.  There were no major problems encountered with
relaying information with the use of backup telecommunications
systems.  AEP and other utilities also participated in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.  The drill gave
electric utilities in North America an opportunity to test how
workers would respond in emergency situations, such as an outage at
a major power plant or loss of the normal communications system.
The drill did not reveal any major problems or issues for AEP.
   Through the Electric Power Research Institute, AEP is
participating in an electric utility industry-wide effort that has
been established to deal with Y2K problems affecting embedded
systems.  The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in
accordance with business risk.  The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy, and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
   The AEP System has completed the process of modifying,
replacing, retiring and testing those mission critical and high
priority digital-based systems with problems processing dates in
the Year 2000.
   The Company has upgraded its meteorological reporting system
used at the Donald C. Cook Nuclear Plant, a mission critical IT
system, for Y2K readiness.  It was originally anticipated that the
upgrade was to have been completed by December 15, 1999.
Costs to Address the Company's Year 2000 Issues - Through September
30, 1999, the Company has spent $7 million on the Y2K project and,
estimates spending an additional $1 million to $3 million to
achieve Y2K readiness.  Most Y2K costs are for software
modifications, IT consultants and salaries and are expensed;
however, in certain cases the Company has acquired hardware that
was capitalized.  The Company intends to fund these expenditures
through internal sources.  The Company has benefited from the
sharing of costs with its affiliates in the AEP System.  The cost
of becoming Y2K 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 Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
   Automated power generation, transmission and distribution     systems
   Telecommunications systems
   Energy trading systems
   Time-in-use, demand and remote metering systems for commercial
   and industrial customers and
   Work management and billing systems.

   The potential problems related to erroneous processing by, or
failure of, these systems are:
   Power service interruptions to customers
   Interrupted revenue data gathering and collection
   Poor customer relations resulting from delayed billing and
   settlement.

   Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restored.
   In addition, although relationships with third parties, such
as suppliers, customers and other electric utilities, are being
monitored, these third parties nonetheless represent a risk that
cannot be assessed with precision or controlled with certainty.
   Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Y2K-related issues could materially adversely affect the Company.

Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a Y2K contingency plan and
submitted it to the East Central Area Reliability Council (ECAR) as
part of NERC's review of regional and individual electric utility
contingency plans in 1999.  In addition, the Company has
established detailed contingency plans for its business units to
address alternatives if Y2K related failures occur, including an
operating plan which is coordinated with other ECAR member
utilities.  These contingency plans will be refined by the end of
1999.

   The Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place and
include:
   Availability of additional power generation reserves.
   Coal inventory of approximately 45 days of normal usage.
   Identifying critical operational locations, in order to place
   key employees on duty at those locations during the Y2K
   transition.

<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                           STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                           Three Months Ended        Nine Months Ended
                                              September 30,            September 30,
                                             1999       1998         1999         1998
                                                          (in thousands)
<S>                                        <C>       <C>           <C>          <C>
OPERATING REVENUES . . . . . . . . . . . . $94,939   $104,922      $271,911     $276,288

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . .  18,258     21,478        60,233       61,963
  Purchased Power. . . . . . . . . . . . .  32,177     31,548        82,524       79,878
  Other Operation. . . . . . . . . . . . .  10,607     13,647        34,726       36,633
  Maintenance. . . . . . . . . . . . . . .   5,522      7,335        15,360       23,759
  Depreciation and Amortization. . . . . .   7,356      7,068        21,833       20,956
  Taxes Other Than Federal Income Taxes. .   2,967      2,668         8,183        7,420
  Federal Income Taxes . . . . . . . . . .   3,808      4,627         9,215        7,406

         TOTAL OPERATING EXPENSES. . . . .  80,695     88,371       232,074      238,015

OPERATING INCOME . . . . . . . . . . . . .  14,244     16,551        39,837       38,273

NONOPERATING INCOME (LOSS) . . . . . . . .     111       (902)          (44)      (1,066)

INCOME BEFORE INTEREST CHARGES . . . . . .  14,355     15,649        39,793       37,207

INTEREST CHARGES . . . . . . . . . . . . .   7,158      7,207        21,392       21,335

NET INCOME . . . . . . . . . . . . . . . . $ 7,197   $  8,442      $ 18,401     $ 15,872




                      STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended        Nine Months Ended
                                              September 30,            September 30,
                                             1999        1998        1999         1998
                                                          (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . $67,770     $71,356      $71,452      $78,076

NET INCOME . . . . . . . . . . . . . . . .   7,197       8,442       18,401       15,872

CASH DIVIDENDS DECLARED. . . . . . . . . .   7,443       7,075       22,329       21,225

BALANCE AT END OF PERIOD . . . . . . . . . $67,524     $72,723      $67,524      $72,723



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

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                         September 30,    December 31,
                                                             1999             1998
                                                                (in thousands)
ASSETS
<S>                                                       <C>              <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .    $  267,680       $  267,201
  Transmission . . . . . . . . . . . . . . . . . . . .       342,366          326,989
  Distribution . . . . . . . . . . . . . . . . . . . .       360,289          351,407
  General. . . . . . . . . . . . . . . . . . . . . . .        66,934           68,038
  Construction Work in Progress. . . . . . . . . . . .        28,194           30,076
          Total Electric Utility Plant . . . . . . . .     1,065,463        1,043,711
  Accumulated Depreciation and Amortization. . . . . .       334,057          315,546

          NET ELECTRIC UTILITY PLANT . . . . . . . . .       731,406          728,165

OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        17,048           12,078

CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         1,065            1,935
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .        17,702           23,295
    Affiliated Companies . . . . . . . . . . . . . . .         8,945            8,797
    Miscellaneous. . . . . . . . . . . . . . . . . . .         4,716            4,019
    Allowance for Uncollectible Accounts . . . . . . .          (769)            (848)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .        12,386            7,888
  Materials and Supplies . . . . . . . . . . . . . . .        16,916           13,652
  Accrued Utility Revenues . . . . . . . . . . . . . .         9,226           13,560
  Energy Marketing and Trading Contracts . . . . . . .        22,536            4,726
  Prepayments. . . . . . . . . . . . . . . . . . . . .         1,714            1,657

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        94,437           78,681


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        94,321           92,447

DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         6,231           10,476

            TOTAL. . . . . . . . . . . . . . . . . . .    $  943,443       $  921,847

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1999            1998
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                         <C>             <C>
CAPITALIZATION:
  Common Stock - $50 Par Value:
    Authorized -  2,000,000 Shares
    Outstanding - 1,009,000 Shares . . . . . . . . . .      $ 50,450        $ 50,450
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       158,750         148,750
  Retained Earnings. . . . . . . . . . . . . . . . . .        67,524          71,452
          Total Common Shareholder's Equity. . . . . .       276,724         270,652
  Long-term Debt . . . . . . . . . . . . . . . . . . .       260,838         308,838

          TOTAL CAPITALIZATION . . . . . . . . . . . .       537,562         579,490

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        24,402          26,827

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .        60,000          60,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .        65,965          20,350
  Accounts Payable - General . . . . . . . . . . . . .        10,671          12,917
  Accounts Payable - Affiliated Companies. . . . . . .        11,448          11,814
  Customer Deposits. . . . . . . . . . . . . . . . . .         4,068           4,038
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         6,894           7,256
  Interest Accrued . . . . . . . . . . . . . . . . . .         7,913           6,241
  Energy Marketing and Trading Contracts . . . . . . .        21,685           5,089
  Other. . . . . . . . . . . . . . . . . . . . . . . .        13,268          13,612

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       201,912         141,317

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       160,954         158,706

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        13,298          14,200

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .         5,315           1,307

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .      $943,443        $921,847

See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                          KENTUCKY POWER COMPANY
                         STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                Nine Months Ended
                                                                  September 30,
                                                                1999          1998
                                                                  (in thousands)
<S>                                                           <C>           <C>
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 18,401      $ 15,872
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    21,838        20,966
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     2,361         1,173
    Deferred Investment Tax Credits. . . . . . . . . . . . .      (902)         (915)
    Amortization of Deferred Property Taxes. . . . . . . . .     4,035         3,840
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .     4,669        (4,514)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    (7,762)        1,227
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     4,334         1,394
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (2,612)       (3,757)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .      (362)       (1,193)
  Payment of Disputed Taxes and Interest Related to COLI . .      (567)       (5,376)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .    (1,138)        1,952
        Net Cash Flows From Operating Activities . . . . . .    42,295        30,669

INVESTING ACTIVITIES - Construction Expenditures . . . . . .   (28,144)      (30,517)

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .    10,000        10,000
  Change in Short-term Debt (net). . . . . . . . . . . . . .    45,615        12,850
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (48,307)       (2,203)
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .   (22,329)      (21,225)
        Net Cash Flows Used For Financing Activities . . . .   (15,021)         (578)

Net Decrease in Cash and Cash Equivalents. . . . . . . . . .      (870)         (426)
Cash and Cash Equivalents at Beginning of Period . . . . . .     1,935         1,381
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  1,065      $    955

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was  $19,420,000 and $18,950,000
  and for income taxes was $7,271,000 and $5,812,000 in 1999 and 1998, respectively.
  Noncash acquisitions under capital leases  were $1,889,000 and $4,448,000  in 1999
  and 1998, respectively.


See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
                          KENTUCKY POWER COMPANY
                       NOTES TO FINANCIAL STATEMENTS
                             SEPTEMBER 30, 1999
                                (UNAUDITED)

1. GENERAL

       The accompanying unaudited financial statements should be read in
   conjunction with the 1998 Annual Report as incorporated in and filed with
   the Form 10-K.  Certain prior-period amounts have been reclassified to
   conform to current-period presentation.  In the opinion of management,
   the financial statements reflect all normal recurring accruals and
   adjustments which are necessary for a fair presentation of the results
   of operations for interim periods.

2. FINANCING ACTIVITIES

       In 1999 the following amounts of long-term debt were redeemed: a $25
   million term loan note with a rate of 6.42% in April; $12.8 million
   principal amount of the 7.90% Series First Mortgage Bonds in May; and
   $10.5 million principal amount of the remaining 7.90% Series First
   Mortgage Bonds in  August.

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

       During the first nine months of 1999, the Company increased
   short-term debt by $45.6 million.

3. NEW ACCOUNTING STANDARDS

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

4. RATE MATTERS

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

       On July 9, 1996, the AEP System companies filed an Open Access
   Transmission Tariff conforming with the FERC's pro-forma transmission
   tariff, subject to the resolution of certain pricing issues.  The 1996
   tariff incorporated transmission rates which were the result of a
   settlement of a pending rate case, but which were being collected subject
   to refund from certain customers who opposed the settlement and continued
   to litigate the reasonableness of AEP's transmission rates.  On July 29,
   1999, the FERC issued an order in the litigated rate case which would
   reduce AEP's rates for the affected customers below the settlement rate.
   AEP and certain of the affected customers have sought rehearing of the
   Commission's Order.  The Company made a provision in September 1999 for
   its share of the refund which it anticipates would result if the
   Commission's order is upheld including interest.

5. CONTINGENCIES

   Litigation

       As discussed in Note 3, of the Notes to Financial Statements in the
   1998 Annual Report, the deductibility of certain interest deductions
   related to American Electric Power's corporate owned life insurance
   (COLI) program for taxable years 1992-1996 is under review by the
   Internal Revenue Service (IRS).  Adjustments have been or will be
   proposed by the IRS disallowing COLI interest deductions.  A disallowance
   of COLI interest deductions through September 30, 1999 would reduce
   earnings by approximately $8 million (including interest).  The Company
   has made no provision for any possible earnings impact from this matter.

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

       In order to resolve this issue, the Company filed suit against the
   United States in the U.S. District Court for the Southern District of
   Ohio in March 1998. A US Tax Court judge recently decided in the
   Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI
   interest deductions should be disallowed.  Notwithstanding the decision
   in Winn-Dixie, management believes, and has been  advised by outside
   counsel, that it has a meritorious position and will vigorously pursue
   its lawsuit.  In the event the resolutions of this matter is unfavorable,
   it will  have a material adverse impact on results of operations and cash
   flows.

<PAGE>
   Air Quality

       As discussed in Note 3 of the Notes to Financial Statements in the
   1998 Annual Report, the U.S. Environmental Protection Agency (Federal
   EPA) issued final rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which the
   generating plants of the Company and its AEP System affiliates are
   located.  A number of utilities, including the Company and its AEP System
   affiliates, filed petitions seeking a review of the final rule in the
   U.S. Court of Appeals for the District of Columbia Circuit (Appeals
   Court).  The matter is currently being litigated.

       On April 30, 1999, Federal EPA took final action with respect to
   petitions filed by eight northeastern states pursuant to Section 126 of
   the Clean Air Act.  Federal EPA approved portions of the states'
   petitions that would impose NOx reduction requirements on AEP System
   generating units which are approximately equivalent to the reductions
   contemplated by the NOx emission reduction final rules.  The AEP System
   companies with generating plants, as well as other utility companies,
   filed a petition in the Appeals Court seeking review of Federal EPA's
   approval of portions of the northeastern states' petitions.  In the
   second quarter of 1999, three additional northeastern states filed
   Section 126 petitions with Federal EPA similar to those originally filed
   by the eight northeastern states.

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

   Clean Air Act Threatened Litigation

       In the fall of 1999 the State of New York, various environmental
   groups and the State of Connecticut each separately threatened to sue the
   Company under the Clean Air Act to compel compliance with the New Source
   Review and New Source Performance Standard provisions, alleging that
   modifications occurred at certain units at the Company's Big Sandy Plant.
   Under these provisions of the Clean Air Act, if a plant undertakes a
   major modification that directly results in an emissions increase,
   permitting requirements under the New Source Review program might be
   triggered and the plant may be required to install additional pollution
   control technology.  This requirement does not apply to activities such
   as routine maintenance, replacement of degraded equipment or failed
   components, or other repairs needed for the reliable, safe and efficient
   operation of the plant.  The State of New York also threatened to sue
   five unaffiliated utilities.  In addition, the State of New York
   indicated that it may seek to recover, under state law, compensation for
   alleged environmental damage caused by excess emissions of sulfur dioxide
   and nitrogen oxides.

       Management believes its maintenance, repair and replacement
   activities were in conformity with the Clean Air Act and were exempted
   from the New Source Review and New Source Performance Standard
   requirements, and intends to vigorously pursue its defense of this
   matter.

       In the event the Company does not prevail in any litigation
   ultimately filed, any capital and operating costs of additional pollution
   control equipment that may be required as well as any penalties imposed
   would adversely affect future results of operations, cash flows and
   possibly financial condition unless such costs can be recovered through
   regulated rates and/or reflected in the future market price of
   electricity if generation is deregulated.

   Other

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


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

                 THIRD QUARTER 1999 vs. THIRD QUARTER 1998
                                    AND
                  YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
   Net income decreased $1.2 million or 15% for the quarter and increased
$2.5 million or 16% for the year-to-date period.  The decrease in net income
for the quarter is attributable to lower wholesale power sales margins and a
refund provision for transmission revenues.  The effect on net income of
decreases in revenues in both periods were offset by reductions in operating
expenses.  The increase in year-to-date net income is due predominantly to
such decreases.
   Income statement line items which changed significantly were:
                                    Increase (Decrease)
                            Third Quarter        Year-to-Date
                          (in millions)  %   (in millions)    %

Operating Revenues. . . . . $(10.0)     (10)    $(4.4)        (2)
Fuel Expense. . . . . . . .   (3.2)     (15)     (1.7)        (3)
Purchased Power Expense . .    0.6        2       2.6          3
Other Operation Expense . .   (3.0)     (22)     (1.9)        (5)
Maintenance Expense . . . .   (1.8)     (25)     (8.4)       (35)
Federal Income Taxes. . . .   (0.8)     (18)      1.8         24
Nonoperating Income . . . .    1.0      112       1.0         96

   The decreases in operating revenues for the third quarter and
year-to-date periods were due primarily to a reduction in wholesale power sales
margins and a revenue refund provision for wholesale transmission service.
In the year-to-date period, the decline in wholesale power and transmission
revenues were partially offset by a 3% increase in retail revenues as a
result of colder winter weather.
   Fuel expense decreased in the third quarter due to a decline in
generation reflecting a planned maintenance outage at Big Sandy Plant Unit 2
which began in mid-September 1999.  In the year-to-date period, fuel expense
decreased mainly due to the deferral of fuel cost for later recovery under a
fuel cost recovery mechanism.  Changes in the cost of fuel are deferred until
reflected in fuel clause billings to customers.
   The increase in purchased power expense in the year-to-date period
resulted from increased capacity charges from the American Electric Power
System Power Pool (AEP Power Pool).  Under the terms of the AEP Power Pool,
capacity credits and charges are designed to allocate the cost of the AEP
System's capacity among the AEP Power Pool members based on their relative
peak demands and generating reserves.  The Company pays net capacity charges
to the AEP Power Pool because its peak demand is greater than its internal
generating capacity.  The increase in capacity charges can be attributed to
an increase in the Company's prior twelve month peak demand relative to the
total peak demand of all AEP Power Pool members.
   Other operation expense decreased due to reduced accruals for incentive
compensation and uncollectible accounts.
   The decrease in maintenance expense in the third quarter reflects the
effect of staff reductions.  The decline in maintenance expense in the
year-to-date period is primarily attributable to decreased overhead
distribution line and generating plant maintenance expenditures
and the staff reductions savings.  In the first quarter of 1998 the repair
and restoration of distribution service after winter storm damage
and a lengthy scheduled outage
in the second quarter of 1998 for maintenance and repairs of the 260 mw Big
Sandy Plant Unit 1 increased 1998 maintenance expense.
   Federal income tax attributable to operations decreased in the quarter
due to a decline in pre-tax operating income partially offset by changes in
certain book/tax timing differences accounted for on a flow-through basis for
rate-making and financial reporting purposes.  The increase in federal income
taxes for the year-to-date period resulted from an increase in pre-tax
operating income and changes in certain book/tax timing differences accounted
for on a flow-through basis for rate-making and financial reporting purposes.
   Nonoperating income increased due to the effect of losses recorded in
1998 on certain power marketing and trading transactions.  These
transactions, which are marked-to-market, represent non-regulated trading
activities outside the Company's traditional marketing area.

<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
<CAPTION>
                                          Three Months Ended         Nine Months Ended
                                             September 30,             September 30,
                                           1999        1998          1999         1998
                                                         (in thousands)
<S>                                      <C>         <C>          <C>          <C>
OPERATING REVENUES . . . . . . . . . . . $544,451    $597,812     $1,561,259   $1,637,155
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .  173,857     199,934        532,075      574,156
  Purchased Power. . . . . . . . . . . .   68,836      60,497        125,808      128,487
  Other Operation. . . . . . . . . . . .   81,113      96,254        249,003      260,097
  Maintenance. . . . . . . . . . . . . .   27,434      34,900         81,425       98,651
  Depreciation and Amortization. . . . .   37,509      36,236        111,691      108,097
  Taxes Other Than Federal Income Taxes.   42,941      42,931        128,746      127,451
  Federal Income Taxes . . . . . . . . .   39,903      38,222        107,369      102,444

          TOTAL OPERATING EXPENSES . . .  471,593     508,974      1,336,117    1,399,383
OPERATING INCOME . . . . . . . . . . . .   72,858      88,838        225,142      237,772
NONOPERATING INCOME (LOSS) . . . . . . .    4,856      (2,665)         6,364        2,022
INCOME BEFORE INTEREST CHARGES . . . . .   77,714      86,173        231,506      239,794
INTEREST CHARGES . . . . . . . . . . . .   21,481      20,212         62,587       60,338
NET INCOME . . . . . . . . . . . . . . .   56,233      65,961        168,919      179,456
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      364         369          1,098        1,107
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 55,869    $ 65,592     $  167,821   $  178,349



               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended         Nine Months Ended
                                             September 30,             September 30,
                                           1999        1998          1999         1998
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $584,045    $597,357     $587,500       $590,151
NET INCOME . . . . . . . . . . . . . . .   56,233      65,961      168,919        179,456
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   57,704      52,775      173,110        158,325
    Cumulative Preferred Stock . . . . .      366         369        1,101          1,108

BALANCE AT END OF PERIOD . . . . . . . . $582,208    $610,174     $582,208       $610,174

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

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1999            1998
                                                                 (in thousands)
ASSETS
<S>                                                        <C>             <C>
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,688,839      $2,646,597
  Transmission . . . . . . . . . . . . . . . . . . . .        852,726         842,318
  Distribution . . . . . . . . . . . . . . . . . . . .        975,947         949,224
  General (including mining assets). . . . . . . . . .        728,744         689,815
  Construction Work in Progress. . . . . . . . . . . .        118,395         129,887
          Total Electric Utility Plant . . . . . . . .      5,364,651       5,257,841
  Accumulated Depreciation and Amortization. . . . . .      2,600,110       2,461,376

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,764,541       2,796,465


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        240,305         218,311


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .        136,765          89,652
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .        303,690         215,665
    Affiliated Companies . . . . . . . . . . . . . . .         91,718          63,922
    Miscellaneous. . . . . . . . . . . . . . . . . . .         23,473          28,139
    Allowance for Uncollectible Accounts . . . . . . .         (3,175)         (1,678)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .        139,431          94,914
  Materials and Supplies . . . . . . . . . . . . . . .         93,539          86,870
  Accrued Utility Revenues . . . . . . . . . . . . . .         38,146          43,501
  Energy Marketing and Trading Contracts . . . . . . .         89,217          19,790
  Prepayments and Other Current Assets . . . . . . . .         34,474          34,523

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        947,278         675,298



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        627,432         551,776


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         45,219         102,830



            TOTAL. . . . . . . . . . . . . . . . . . .     $4,624,775      $4,344,680


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
<CAPTION>
                                                          September 30,   December 31,
                                                              1999            1998
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                        <C>             <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  40,000,000 Shares
    Outstanding - 27,952,473 Shares. . . . . . . . . .     $  321,201      $  321,201
  Paid-in Capital. . . . . . . . . . . . . . . . . . .        462,317         462,335
  Retained Earnings. . . . . . . . . . . . . . . . . .        582,208         587,500
          Total Common Shareholder's Equity. . . . . .      1,365,726       1,371,036
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .         17,121          17,370
    Subject to Mandatory Redemption. . . . . . . . . .          8,850          11,850
  Long-term Debt . . . . . . . . . . . . . . . . . . .      1,142,610       1,073,456

          TOTAL CAPITALIZATION . . . . . . . . . . . .      2,534,307       2,473,712

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        419,733         360,330

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .         11,480          11,472
  Short-term Debt. . . . . . . . . . . . . . . . . . .         97,605         123,005
  Accounts Payable - General . . . . . . . . . . . . .        252,513         173,369
  Accounts Payable - Associated Companies. . . . . . .         97,837          62,418
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         88,276         161,406
  Interest Accrued . . . . . . . . . . . . . . . . . .         22,646          14,187
  Obligations Under Capital Leases . . . . . . . . . .         33,068          28,310
  Energy Marketing and Trading Contracts . . . . . . .         86,406          22,480
  Other. . . . . . . . . . . . . . . . . . . . . . . .        109,317          97,916

          TOTAL CURRENT LIABILITIES. . . . . . . . . .        799,148         694,563

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .        700,803         711,913

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .         36,817          39,296

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        133,967          64,866

CONTINGENCIES (Note 7)

            TOTAL. . . . . . . . . . . . . . . . . . .     $4,624,775      $4,344,680


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                    OHIO POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
<CAPTION>
                                                                  Nine Months Ended
                                                                    September 30,
                                                                 1999           1998
                                                                    (in thousands)
OPERATING ACTIVITIES:
  <S>                                                         <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 168,919      $ 179,456
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . .    146,388        129,366
    Deferred Federal Income Taxes. . . . . . . . . . . . . .      7,529         12,504
    Amortization of Deferred Property Taxes. . . . . . . . .     59,567         58,664
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .   (109,658)      (128,584)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    (51,186)        28,200
    Accrued Utility Revenues . . . . . . . . . . . . . . . .      5,355         (6,314)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    114,563        145,687
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (73,130)       (45,620)
    Other Current Assets and Current Liabilities . . . . . .     19,166         22,853
  Payment of Disputed Tax and Interest Related to COLI . . .     (6,272)      (104,222)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     26,829         68,381
        Net Cash Flows From Operating Activities . . . . . .    308,070        360,371

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (126,524)      (121,310)
  Proceeds from Sale of Property and Other . . . . . . . . .      2,003          4,348
        Net Cash Flows Used For Investing Activities . . . .   (124,521)      (116,962)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    222,308        137,566
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (25,400)        20,108
  Retirement of Cumulative Preferred Stock . . . . . . . . .     (3,267)           (52)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (155,866)      (190,181)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (173,110)      (158,325)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,101)        (1,108)
        Net Cash Flows Used For Financing Activities . . . .   (136,436)      (191,992)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     47,113         51,417
Cash and Cash Equivalents at Beginning of Period . . . . . .     89,652         44,203
Cash and Cash Equivalents at End of Period . . . . . . . . .  $ 136,765      $  95,620

Supplemental Disclosure:
  Cash paid for  interest net  of capitalized amounts was  $52,526,000 and $52,523,000
  and for income taxes was $48,052,000 and $55,898,000 in 1999 and 1998, respectively.
  Noncash acquisitions  under capital leases  were $23,955,000 and $24,740,000 in 1999
  and 1998, respectively.


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
               OHIO POWER COMPANY AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        SEPTEMBER 30, 1999
                           (UNAUDITED)

1. GENERAL

       The accompanying unaudited consolidated financial state-ments
   should be read in conjunction with the 1998 Annual Report
   as incorporated in and filed with the Form 10-K.  Certain
   prior-period amounts have been reclassified to conform to
   current-period presentation.  In the opinion of management, the
   financial statements reflect all normal recurring accruals and
   adjustments which are necessary for a fair presentation of the
   results of operations for interim periods.

2. FINANCING ACTIVITY

       In May 1999 the Company issued $50 million of 5.15% Air
   Quality Series C pollution control revenue bonds due 2026.  In
   June 1999 the Company issued $100 million of 6.75% senior
   unsecured notes due 2004 and in September 1999 the Company
   issued $75 million of 7% senior unsecured notes also due in
   2004.

       During the first nine months of 1999, the Company
   reacquired the following first mortgage bonds:
                                        Principal
                                        Amount
       % Rate      Due Date         Reacquired
                                      (in thousands)
       6.875       June 1, 2003      $40,000
       6.55        October 1, 2003         7,865
       7.85        June 1, 2023           40,000
       7.10        November 1, 2023        2,000

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

       During the first nine months of 1999 the Company decreased
   short-term debt by $25.4 million.

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

3. NEW ACCOUNTING STANDARDS

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

4. OHIO RESTRUCTURING LEGISLATION

       The Ohio Electric Restructuring Act of 1999 became law on
   October 4, 1999.  The law provides for customer choice of
   electricity supplier, a residential rate reduction of 5% and
   a freezing of the unbundled generation base rates and a
   freezing of fuel rates beginning on January 1, 2001.  The law
   also provides for a five-year transition period to transition
   from cost based rates to market pricing for generation
   services.  It authorizes the Public Utilities Commission of
   Ohio (PUCO) to address certain major transition issues
   including unbundling of rates and the recovery of regulatory
   assets including any unrecovered deferred fuel costs, stranded
   plant and mining costs and other transition costs.

       Retail electric services that will be competitive are
   defined in the law as electric generation service, aggregation
   service, and power marketing and brokering.  Under the
   legislation the PUCO is granted broad oversight responsibility
   and is required by the law to promulgate rules for competitive
   retail electric generation service.  The law also gives the
   PUCO authority to approve a transition plan for each electric
   utility company.

       The law provides Ohio electric utilities with an
   opportunity to recover PUCO approved allowable transition costs
   through unbundled frozen generation rates paid through December
   31, 2005 by customers who do not switch generation suppliers
   and through a wires charge for customers who switch generation
   suppliers.  Transition costs can include regulatory assets,
   impairments of generating assets and other stranded costs,
   employee severance and retraining costs, consumer education
   costs and other costs.  Recovery of transition costs can, under
   certain circumstances, extend beyond the five-year frozen rate
   transition period  but cannot continue beyond December 31,
   2010.  The Company must file a transition plan with the PUCO
   by January 3, 2000 and the PUCO is required to issue a
   transition order no later than October 31, 2000.

       The law also provides that the property tax assessment
   percentage on electric generation property be lowered from 100%
   to 25% of value effective January 1, 2001.  Electric utilities
   will become subject to the Ohio Corporate Franchise Tax and
   municipal income taxes on January 1, 2002.  The last year for
   which electric utilities will pay the excise tax based on gross
   receipts is the tax year ending April 30, 2002.  As of May 1,
   2001 electric distribution companies will be subject to an
   excise tax based on kilowatt-hours sold to Ohio customers.  The
   gross receipts tax is paid at the beginning of the tax year,
   deferred as a prepaid expense and amortized to expense during
   the tax year pursuant to the tax laws whereby the payment of
   the tax results in the privilege to conduct business in the
   year following the payment of the tax.  The change in the tax
   law to impose an excise tax based on kilowatt-hours sold to
   Ohio customers commencing before the expiration of the gross
   receipts tax privilege period will result in a 12 month period
   when electric utilities are recording as an expense both the
   gross receipts tax and the excise tax.  Management intends to
   seek recovery of the overlap of the gross receipts and excise
   taxes in the Ohio transition plan filing.

       As discussed in Note 2, "Effects of Regulation," of the
   Notes to Consolidated Financial Statements in the 1998 Annual
   Report, the Company defers as regulatory assets and liabilities
   certain expenses and revenues consistent with the regulatory
   process in accordance with Statement of Financial Accounting
   Standards (SFAS) 71, "Accounting for the Effects of Certain
   Types of Regulation."  Management has concluded that as of
   September 30, 1999 the requirements to apply SFAS 71 continue
   to be met since the Company's rates for generation will
   continue to be cost-based regulated until the establishment of
   unbundled frozen generation rates and a wires charge as
   provided in the law.  The establishment of unbundled frozen
   generation rates and the wires charge should enable the Company
   to determine its ability to recover transition costs including
   regulatory assets and other stranded costs, a requirement to
   discontinue application of SFAS 71.

       When unbundled generation rates and the wires charge are
   established, the application of SFAS 71 will be discontinued
   for the Ohio retail jurisdiction portion of the  generation
   business.  At that time the Company will have to write-off its
   Ohio jurisdictional generation-related regulatory assets to the
   extent that they cannot be recovered under the unbundled frozen
   generation rates and distribution wires charges approved by the
   PUCO under the provisions of the restructuring law and record
   any asset impairments in accordance with SFAS 121, "Accounting
   for the Impairment of Long-lived Assets and for Long-lived
   Assets to Be Disposed Of."  An impairment loss would be
   recorded to the extent that the cost of generation assets
   cannot be recovered through the transition recovery mechanisms
   provided by the law and future market prices.  Absent the
   determination in the regulatory process of an unbundled frozen
   generation rate, the wires charge and other pertinent
   information, it is not possible at this time to determine if
   any of the Company's generating assets are impaired in
   accordance with SFAS 121.  The amount of regulatory assets
   recorded on the books at September 30, 1999 applicable to the
   Ohio retail jurisdictional generating business is $327 million
   before related tax effects.  Due to the planned closing of
   affiliated mines including the Meigs mine, and other
   anticipated events, generation-related regulatory assets as of
   December 31, 2000 allocable to the Ohio retail jurisdiction are
   estimated to exceed $500 million, before federal income tax
   effects.  Recovery of these regulatory assets will be sought
   as a part of the Company's Ohio transition plan filing.

       An estimated determination of whether the Company will
   experience any asset impairment loss regarding its Ohio retail
   jurisdictional generating assets and any loss from a possible
   inability to recover Ohio generation related regulatory assets
   and other transition costs cannot be made until such time as
   the unbundled frozen generation rates and the wires charge are
   determined through the regulatory process.  Management will
   seek full recovery of generation-related regulatory assets, any
   stranded costs and other transition costs in its transition
   plan filing.  The PUCO is required to complete its regulatory
   process and issue a transition order establishing the
   transition rates and wires charges by no later than October 31,
   2000.  Should the PUCO fail to approve transition rates and
   wires charges that are sufficient to recover the Company's
   generation-related regulatory assets, any other stranded costs
   and transition costs, it could have a material adverse effect
   on results of operations, cash flows and financial condition.

5. MUSKINGUM AND WINDSOR MINE CLOSING

       In July 1999 the Company announced that the scheduled
   closing of the affiliated Windsor coal mine was being
   accelerated from December 31, 2000 to April 30, 2000.  The
   liability for closing the Windsor mine is estimated to be $48.4
   million.  In October 1999 the Company closed the Muskingum coal
   mine.

       As discussed in Note 3, "Rate Matters" of the Notes to
   Consolidated Financial Statements in the 1998 Annual Report,
   management believes the Ohio jurisdictional portion of the cost
   of the mine shutdowns can be deferred for future recovery
   through the Ohio fuel clause mechanism under terms of the Ohio
   fuel clause predetermined price agreement.  At September 30,
   1999 the Company has deferred $158 million under the terms of
   the Ohio fuel clause predetermined price agreement.  Management
   intends to continue to recover from non-Ohio jurisdictional
   ratepayers the non-Ohio jurisdictional portion of the
   investment in and the liabilities and closing costs of the
   Muskingum and Windsor mines.  Unless the cost of the remaining
   coal production and deferred mine shutdowns are recovered
   through the remaining Ohio fuel clause rates and Ohio
   restructuring transition rates and/or a wires charge, results
   of operations and cash flows would be adversely affected.

6. RATE MATTERS

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

       On July 9, 1996, the AEP System companies filed an Open
   Access Transmission Tariff conforming with the FERC's pro-forma
   transmission tariff, subject to the resolution of certain
   pricing issues.  The 1996 tariff incorporated transmission
   rates which were the result of a settlement of a pending rate
   case, but which were being collected subject to refund from
   certain customers who opposed the settlement and continued to
   litigate the reasonableness of AEP's transmission rates.  On
   July 29, 1999, the FERC issued an order in the litigated rate
   case which would reduce AEP's rates for the affected customers
   below the settlement rate.  AEP and certain of the affected
   customers have sought rehearing of the Commission's Order.  The
   Company made a provision in September 1999 for its share of the
   refund which it anticipates would result if the Commission's
   order is upheld including interest.

7. CONTINGENCIES

   Litigation

       As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the
   deductibility of certain interest deductions related to
   American Electric Power's corporate owned life insurance (COLI)
   program for taxable years 1991-1996 is under review by the
   Internal Revenue Service (IRS).  Adjustments have been or will
   be proposed by the IRS disallowing COLI interest deductions.
   A disallowance of COLI interest deductions through September
   30, 1999 would reduce earnings by approximately $117 million
   (including interest).  The Company has made no provision for
   any possible earnings impact from this matter.

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

       In order to resolve this issue, the Company filed suit
   against the United States in the US District Court for the
   Southern District of Ohio in March 1998.  A US Tax Court judge
   recently decided in the Winn-Dixie Stores v. Commissioner case
   that a corporate taxpayer's COLI interest deductions should be
   disallowed.  Notwithstanding the decision in Winn-Dixie,
   management believes, and has been  advised by outside counsel,
   that it has a meritorious position and will vigorously pursue
   its lawsuit.  In the event the resolution of this matter is
   unfavorable, it will have a material adverse impact on results
   of operations and cash flows.

   Air Quality

       As discussed in Note 4 of the Notes to Consolidated
   Financial Statements in the 1998 Annual Report, the U.S.
   Environmental Protection Agency (Federal EPA) issued final
   rules which require reductions in nitrogen oxides (NOx)
   emissions in 22 eastern states, including the states in which
   the generating plants of the Company and its AEP System
   affiliates are located.  A number of utilities, including the
   Company and its AEP System affiliates, filed petitions seeking
   a review of the final rules in the U.S. Court of Appeals for
   the District of Columbia Circuit (Appeals Court).  The matter
   is currently being litigated.

       On April 30, 1999, Federal EPA took final action with
   respect to petitions filed by eight northeastern states
   pursuant to Section 126 of the Clean Air Act.  Federal EPA
   approved portions of the states' petitions that would impose
   NOx reduction requirements on AEP System generating units which
   are approximately equivalent to the reductions contemplated by
   the NOx emission reduction final rules.  The AEP System
   companies with generating plants, as well as other utility
   companies, filed a petition in the Appeals Court seeking review
   of Federal EPA's approval of portions of the northeastern
   states' petitions.  In the second quarter of 1999, three
   additional northeastern states filed Section 126 petitions with
   Federal EPA similar to those originally filed by the eight
   northeastern states.

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

<PAGE>
   Federal EPA Complaint and Notice of Violation

       On November 3, 1999 the Department of Justice, at the
   request of Federal EPA, filed a complaint in the U.S. District
   Court for the Southern District of Ohio that alleges the
   Company made modifications to generating units at its Muskingum
   River, Mitchell, Philip Sporn and Cardinal plants over the
   course of the past 25 years to extend unit operating lives or
   to increase unit generating capacity without a preconstruction
   permit in violation of the Clean Air Act.  Federal EPA also
   issued a Notice of Violation to the Company alleging violations
   of the New Source Review and New Source Performance Standard
   provisions of the Clean Air Act at these same plants.  A number
   of unaffiliated utilities also received Notices of Violation,
   complaints or administrative orders.

       Federal EPA's Notice of Violation and the government's
   complaint are based on an investigation by Federal EPA to
   assess compliance with the New Source Review and New Source
   Performance Standard provisions of the Clean Air Act.  Under
   these provisions of the Clean Air Act, if a plant undertakes
   a major modification that directly results in an emissions
   increase, permitting requirements under the New Source Review
   program might be triggered and the plant may be required to
   install additional pollution control technology.  This
   requirement does not apply to activities such as routine
   maintenance, replacement of degraded equipment or failed
   components, or other repairs needed for the reliable, safe and
   efficient operation of the plant.

       In the fall of 1999 the State of New York, various
   environmental groups and the State of Connecticut each
   separately threatened to sue the Company under the Clean Air
   Act to compel compliance with the New Source Review and New
   Source Performance Standard provisions, alleging that
   modifications occurred at certain units at the Company's Philip
   Sporn Plant, Kammer Plant, Mitchell Plant, Muskingum River
   Plant, Gavin Plant and Cardinal Plant.  The State of New York
   also threatened to sue five unaffiliated utilities.  In
   addition, the State of New York indicated that it may seek to
   recover, under state law, compensation for alleged
   environmental damage caused by excess emissions of sulfur
   dioxide and nitrogen oxides.

       Management believes its maintenance, repair and replacement
   activities were in conformity with the Clean Air Act and were
   exempted from the New Source Review and New Source Performance
   Standard requirements, and intends to vigorously pursue its
   defense of this matter.

       The Clean Air Act authorizes civil penalties of up to
   $27,500 per day per violation at each generating unit ($25,000
   per day prior to January 30, 1997).  Civil penalties, if
   ultimately imposed by the court, and the cost of any required
   new pollution control equipment, if the court accepts all of
   Federal EPA's contentions, could be  substantial.

       In the event the Company does not prevail, any capital and
   operating costs of additional pollution control equipment that
   may be required as well as any penalties imposed would
   adversely affect future results of operations, cash flows and
   possibly financial condition unless such costs can be recovered
   through PUCO approved unbundled generation transition rates,
   wires charges and the future market price for electricity.

   Other

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


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

            THIRD QUARTER 1999 vs. THIRD QUARTER 1998
                               AND
             YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
   Net income decreased $9.7 million or 15% for the quarter and
$10.5 million or 6% for the year-to-date period primarily due to a
decline in energy sales to wholesale customers and a decline in
wholesale margins.
   Income statement line items which changed significantly were:
                                    Increase (Decrease)
                             Third Quarter       Year-to-Date
                          (in millions)   %   (in millions)    %

Operating Revenues. . . .    $(53.4)     (9)     $(75.9)      (5)
Fuel Expense. . . . . . .     (26.1)    (13)      (42.1)      (7)
Purchased Power . . . . .       8.3      14        (2.7)      (2)
Other Operation Expense .     (15.1)    (16)      (11.1)      (4)
Maintenance Expense . . .      (7.5)    (21)      (17.2)     (17)
Nonoperating Income . . .       7.5     N.M.        4.3      215

N.M. = Not Meaningful

   Operating revenues decreased significantly in both the third
quarter and year-to-date periods due predominantly to declines in
wholesale sales and margins and a revenue refund provision for
wholesale transmission service.  Operating revenues from wholesale
sales declined significantly as a result of decreased sales to the
American Electric Power System Power Pool (AEP Power Pool) and
unaffiliated entities reflecting the effect of mild weather on
demand.  Wholesale margins declined due to the effects of mild
weather especially during August.
   The decreases in fuel expense for the third quarter and year-to-date
periods were mainly due to a decrease in generation,
reflecting the decline in demand and an increase in the deferral of
fuel cost to be recovered in future periods under the Ohio fuel
clause mechanism.

<PAGE>
   Purchased power expense increased in the third quarter
primarily due to increased purchases from unaffiliated companies at
premium prices during periods of extremely high demand in July
1999.
   Other operation expense decreased in both periods primarily due
to reduced accruals for incentive compensation, cost savings from
staffing reductions and an increase in gains on emission allowance
sales.
   The decreases in maintenance expense in both periods were
mainly due to decreased boiler plant maintenance reflecting a
reduction in planned maintenance work on the Company's generating
units and costs savings from staff reductions at the Company's
generating plants.
   The increase in nonoperating income is primarily due to the
effect of losses in 1998 on certain non-regulated power marketing
and trading transactions outside the AEP Power Pool's traditional
marketing area.
FINANCIAL CONDITION
   Total plant and property additions including capital leases for
the first nine months of 1999 were $150 million.
   During the first nine months of 1999, the Company reacquired
$90 million principal amount of first mortgage bonds with interest
rates ranging from 6.55% to 7.85% and issued two series of senior
unsecured notes of $100 million and $75 million with rates of 6.75%
and 7%, respectively, both due in 2004.  The Company retired $50
million of 7.40% pollution control revenue bonds and issued $50
million of pollution control revenue bonds at 5.15% due 2026.
During the first nine months of 1999 the Company reduced short-term
debt by $25.4 million.
   The short-term debt limitation of the Company was increased
from $400 million to $450 million with approval of the Securities
and Exchange Commission.
OTHER MATTERS
Ohio Restructuring Legislation
   The Ohio Electric Restructuring Act of 1999 became law on
October 4, 1999.  The law provides for customer choice of
electricity supplier, a residential rate reduction of 5% and a
freezing of the unbundled generation base rates and a freezing of
fuel rates beginning on January 1, 2001.  The law also provides for
a five-year transition period to transition from cost based rates
to market pricing for generation services.  It authorizes the
Public Utilities Commission of Ohio (PUCO) to address certain major
transition issues including unbundling of rates and the recovery of
regulatory assets including any unrecovered deferred fuel costs,
stranded plant and mining costs and other transition costs.
   Retail electric services that will be competitive are defined
in the law as electric generation service, aggregation service, and
power marketing and brokering.  Under the legislation the PUCO is
granted broad oversight responsibility and is required by the law
to promulgate rules for competitive retail electric generation
service.  The law also gives the PUCO authority to approve a
transition plan for each electric utility company.
   The law provides Ohio electric utilities with an opportunity
to recover PUCO approved allowable transition costs through
unbundled frozen generation rates paid through December 31, 2005 by
customers who do not switch generation suppliers and through a
wires charge for customers who switch generation suppliers.
Transition costs can include regulatory assets, impairments of
generating assets and other stranded costs, employee severance and
retraining costs, consumer education costs and other costs.
Recovery of transition costs can, under certain circumstances,
extend beyond the five-year frozen rate transition period  but
cannot continue beyond December 31, 2010.  The Company must file a
transition plan with the PUCO by January 3, 2000 and the PUCO is
required to issue a transition order no later than October 31,
2000.
   The law also provides that the property tax assessment
percentage on electric generation property be lowered from 100% to
25% of value effective January 1, 2001.  Electric utilities will
become subject to the Ohio Corporate Franchise Tax and municipal
income taxes on January 1, 2002.  The last year for which electric
utilities will pay the excise tax based on gross receipts is the
tax year ending April 30, 2002.  As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on
kilowatt-hours sold to Ohio customers.  The gross receipts tax is
paid at the beginning of the tax year, deferred as a prepaid
expense and amortized to expense during the tax year pursuant to
the tax laws whereby the payment of the tax results in the
privilege to conduct business in the year following the payment of
the tax.  The change in the tax law to impose an excise tax based
on kilowatt-hours sold to Ohio customers commencing before the
expiration of the gross receipts tax privilege period will result
in a 12 month period when electric utilities are recording as an
expense both the gross receipts tax and the excise tax.  Management
intends to seek recovery of the overlap of the gross receipts and
excise taxes in the Ohio transition plan filing.
   As discussed in Note 2, "Effects of Regulation," of the Notes
to Consolidated Financial Statements in the 1998 Annual Report, the
Company defers as regulatory assets and liabilities certain
expenses and revenues consistent with the regulatory process in
accordance with Statement of Financial Accounting Standards (SFAS)
71, "Accounting for the Effects of Certain Types of Regulation."
Management has concluded that as of September 30, 1999 the
requirements to apply SFAS 71 continue to be met since the
Company's rates for generation will continue to be cost-based
regulated until the establishment of unbundled frozen generation
rates and a wires charge as provided in the law.  The establishment
of unbundled frozen generation rates and the wires charge should
enable the Company to determine its ability to recover transition
costs including regulatory assets and other stranded costs, a
requirement to discontinue application of SFAS 71.
   When unbundled generation rates and the wires charge are
established, the application of SFAS 71 will be discontinued for
the Ohio retail jurisdiction portion of the  generation business.
At that time the Company will have to write-off its Ohio
jurisdictional generation-related regulatory assets to the extent
that they cannot be recovered under the unbundled frozen generation
rates and distribution wires charges approved by the PUCO under the
provisions of the restructuring law and record any asset
impairments in accordance with SFAS 121, "Accounting for the
Impairment of Long-lived Assets and for Long-lived Assets to Be
Disposed Of."  An impairment loss would be recorded to the extent
that the cost of generation assets cannot be recovered through the
transition recovery mechanisms provided by the law and future
market prices.  Absent the determination in the regulatory process
of an unbundled frozen generation rate, the wires charge and other
pertinent information, it is not possible at this time to determine
if any of the Company's generating assets are impaired in
accordance with SFAS 121.  The amount of regulatory assets recorded
on the books at September 30, 1999 applicable to the Ohio retail
jurisdictional generating business is $327 million before related
tax effects.  Due to the planned closing of affiliated mines
including the Meigs mine, and other anticipated events,
generation-related regulatory assets as of December 31, 2000 allocable to the
Ohio retail jurisdiction are estimated to exceed $500 million,
before federal income tax effects.  Recovery of these regulatory
assets will be sought as a part of the Company's Ohio transition
plan filing.
   An estimated determination of whether the Company will
experience any asset impairment loss regarding its Ohio retail
jurisdictional generating assets and any loss from a possible
inability to recover Ohio generation related regulatory assets and
other transition costs cannot be made until such time as the
unbundled frozen generation rates and the wires charge are
determined through the regulatory process.  Management will seek
full recovery of generation-related regulatory assets, any stranded
costs and other transition costs in its transition plan filing.
The PUCO is required to complete its regulatory process and issue
a transition order establishing the transition rates and wires
charges by no later than October 31, 2000.  Should the PUCO fail to
approve transition rates and wires charges that are sufficient to
recover the Company's generation-related regulatory assets, any
other stranded costs and transition costs, it could have a material
adverse effect on results of operations, cash flows and financial
condition.
Muskingum and Windsor Mine Closings
   In July 1999 the Company announced that the scheduled closing
of the affiliated Windsor coal mine was being accelerated from
December 31, 2000 to April 30, 2000.  The liability for closing the
Windsor mine is estimated to be $48.4 million.  In October 1999 the
Company closed the Muskingum coal mine.
   As discussed in Note 3, "Rate Matters" of the Notes to
Consolidated Financial Statements in the 1998 Annual Report,
management believes the Ohio jurisdictional portion of the cost of
the mine shutdowns can be deferred for future recovery through the
Ohio fuel clause mechanism under terms of the Ohio fuel clause
predetermined price agreement.  At September 30, 1999 the Company
has deferred $158 million under the terms of the Ohio fuel clause
predetermined price agreement.  Management intends to continue to
recover from non-Ohio jurisdictional ratepayers the non-Ohio
jurisdictional portion of the investment in and the liabilities and
closing costs of the Muskingum and Windsor mines.  Unless the cost
of the remaining coal production and deferred mine shutdowns are
recovered through the remaining Ohio fuel clause rates and Ohio
restructuring transition rates and/or a wires charge, results of
operations and cash flows would be adversely affected.
COLI Litigation
   As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the deductibility of certain
interest deductions related to American Electric Power's corporate
owned life insurance (COLI) program for taxable years 1991-1996 is
under review by the Internal Revenue Service (IRS).  Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions.  A disallowance of COLI interest deductions through
September 30, 1999 would reduce earnings by approximately $117
million (including interest).  The Company has made no provision
for any possible earnings impact from this matter.
   The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-1998 to avoid
the potential assessment by the IRS of any additional above market
rate interest on the contested amount. These payments to the IRS
are included on the Consolidated Balance Sheets in other property
and investments pending the resolution of this matter.  The Company
is seeking refunds through litigation of all amounts paid plus
interest.
   In order to resolve this issue, the Company filed suit against
the United States in the US District Court for the Southern
District of Ohio in March 1998.  A US Tax Court judge recently
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deductions should be disallowed.
Notwithstanding the decision in Winn-Dixie, management believes,
and has been  advised by outside counsel, that it has a meritorious
position and will vigorously pursue its lawsuit.  In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.
Air Quality
   As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the U.S. Environmental
Protection Agency (Federal EPA) issued final rules which require
reductions in nitrogen oxides (NOx) emissions in 22 eastern states,
including the states in which the generating plants of the Company
and its AEP System affiliates are located.  A number of utilities,
including the Company and its AEP System affiliates, filed
petitions seeking a review of the final rules in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court).  The
matter is currently being litigated.
   On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act.  Federal EPA approved portions of the
states' petitions that would impose NOx reduction requirements on
AEP System generating units which are approximately equivalent to
the reductions contemplated by the NOx emission reduction final
rules.  The AEP System companies with generating plants, as well as
other utility companies, filed a petition in the Appeals Court
seeking review of Federal EPA's approval of portions of the
northeastern states' petitions.  In the second quarter of 1999,
three additional northeastern states filed Section 126 petitions
with Federal EPA similar to those originally filed by the eight
northeastern states.
   Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $570 million for
the Company.  Compliance costs cannot be estimated with certainty.
The actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions.  Unless such costs are recovered from customers through
PUCO approved unbundled generation transition rates, wires charges
and the future market price of electricity, they will have an
adverse effect on future results of operations, cash flows and
possibly financial condition.
Federal EPA Complaint and Notice of Violation
   On November 3, 1999 the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company made
modifications to generating units at its Muskingum River, Mitchell,
Philip Sporn and Cardinal plants over the course of the past 25
years to extend unit operating lives or to increase unit generating
capacity without a preconstruction permit in violation of the Clean
Air Act.  Federal EPA also issued a Notice of Violation to the
Company alleging violations of the New Source Review and New Source
Performance Standard provisions of the Clean Air Act at these same
plants.  A number of unaffiliated utilities also received Notices
of Violation, complaints or administrative orders.
   Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to assess
compliance with the New Source Review and New Source Performance
Standard provisions of the Clean Air Act.  Under these provisions
of the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting
requirements under the New Source Review program might be triggered
and the plant may be required to install additional pollution
control technology.  This requirement does not apply to activities
such as routine maintenance, replacement of degraded equipment or
failed components, or other repairs needed for the reliable, safe
and efficient operation of the plant.
   In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each separately
threatened to sue the Company under the Clean Air Act to compel
compliance with the New Source Review and New Source Performance
Standard provisions, alleging that modifications occurred at
certain units at the Company's Philip Sporn Plant, Kammer Plant,
Mitchell Plant, Muskingum River Plant, Gavin Plant and Cardinal
Plant.  The State of New York also threatened to sue five
unaffiliated utilities.  In addition, the State of New York
indicated that it may seek to recover, under state law,
compensation for alleged environmental damage caused by excess
emissions of sulfur dioxide and nitrogen oxides.
   Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its defense
of this matter.
   The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997).  Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be  substantial.
   In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through PUCO approved
unbundled generation transition rates, wires charges and the future
market price for electricity.
Market Risk
   The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates.  The Company's exposure to market risk from the
trading of electricity and related financial derivative instruments
has not changed materially since December 31, 1998.  Market risk
represents the risk of loss that may impact the Company due to
adverse changes in commodity market prices and interest rates.
   The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at September 30, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
   On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date.  In
addition, certain systems may fail to detect that the year 2000 is
a leap year.  Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company, through the AEP
System, is modifying or replacing its computer hardware and
software programs to minimize Y2K-related failures and repair such
failures if they occur.  This includes both information technology
(IT) systems, which are mainframe and client server applications,
and embedded logic (non-IT) systems, such as process controls for
energy production and delivery.  Externally, the problem is being
addressed with entities that interact with the Company, including
suppliers, customers, creditors, financial service organizations
and other parties essential to the Company's operations.  In the
course of the external evaluation, the Company has sought written
assurances from third parties regarding their state of Y2K
readiness and has been meeting with key vendors in this connection.
   Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The AEP System, along with other electric utilities in North
America, has submitted information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reported summary information to the U.S.
Department of Energy (DOE) regarding the Y2K readiness of electric
utilities.  The fourth and final NERC report, dated August 3, 1999
and entitled: Preparing the Electric Power Systems of North America
for Transition to the Year 2000 - A Status Report and Work Plan,
Second Quarter 1999, states that: "Mission-critical component
testing indicates that the transition through critical Y2K dates is
expected to have minimal impact on electric system operations in
North America."  The report also indicates that, "the risk of
electrical outages caused by Y2K appears to be no higher than the
risks we already experience" from incidents such as severe wind,
ice, floods, equipment failures and power shortages during an
extremely hot or cold period.  NERC has classified the AEP System
as a "Y2K Ready" organization with respect to its electric systems.
   AEP participated in an industry-wide NERC-sponsored drill on
April 9, 1999 simulating the partial loss of voice and data
communications.  There were no major problems encountered with
relaying information with the use of backup telecommunications
systems.  AEP and other utilities also participated in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.  The drill gave
electric utilities in North America an opportunity to test how
workers would respond in emergency situations, such as an outage at
a major power plant or loss of the normal communications system.
The drill did not reveal any major problems or issues for AEP.
   Through the Electric Power Research Institute, AEP is
participating in an electric utility industry-wide effort that has
been established to deal with Y2K problems affecting embedded
systems.  The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in
accordance with business risk.  The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy, and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
   The AEP System has completed the process of modifying,
replacing, retiring and testing those mission critical and high
priority digital-based systems with problems processing dates in
the Year 2000.
Costs to Address the Company's Year 2000 Issues - Through September
30, 1999, the Company has spent $12 million on the Y2K project and,
estimates spending an additional $2 million to $5 million to
achieve Y2K readiness.  Most Y2K costs are for software
modifications, IT consultants and salaries and are expensed;
however, in certain cases the Company has acquired hardware that
was capitalized.  The Company intends to fund these expenditures
through internal sources.  The Company has benefited from the
sharing of Y2K remediation costs with its affiliates in the AEP
System.  The cost of becoming Y2K 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 Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
   Automated power generation, transmission and distribution     systems
   Telecommunications systems
   Energy trading systems
   Time-in-use, demand and remote metering systems for commercial
   and industrial customers and
   Work management and billing systems.
   The potential problems related to erroneous processing by, or
failure of, these systems are:
   Power service interruptions to customers
   Interrupted revenue data gathering and collection
   Poor customer relations resulting from delayed billing and
   settlement.

   Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restored.
   In addition, although relationships with third parties, such
as suppliers, customers and other electric utilities, are being
monitored, these third parties nonetheless represent a risk that
cannot be assessed with precision or controlled with certainty.
   Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Y2K-related issues could materially adversely affect the Company.

Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a Y2K contingency plan and
submitted it to the East Central Area Reliability Council (ECAR) as
part of NERC's review of regional and individual electric utility
contingency plans in 1999.  In addition, the Company has
established detailed contingency plans for its business units to
address alternatives if Y2K related failures occur, including an
operating plan which is coordinated with other ECAR member
utilities.  These contingency plans will be refined by the end of
1999.
   The Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place and
include:
   Availability of additional power generation reserves.
   Coal inventory of approximately 45 days of normal usage.
   Identifying critical operational locations, in order to place
   key employees on duty at those locations during the Y2K
   transition.

<PAGE>
<PAGE>
                   PART II.  OTHER INFORMATION


Item 5.  Other Information.

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

   Reference is made to pages 17 and 18 of the Annual Report on
Form 10-K for the year ended December 31, 1998 ("1998 10-K") and
page II-1 of the Quarterly Report on Form 10-Q for the quarter
ended March 31, 1999, for a discussion of APCo's proposed
transmission facilities.  Based on an extension of the procedural
schedule for the evidentiary hearing in Virginia, management has
revised its completion estimate.  The earliest date that a Wyoming-Jacksons
Ferry line could be in service would be summer 2004.  The
earliest in-service date for the longer Wyoming-Cloverdale line
would be the end of 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")

     On October 20, 1999, the U.S. District Court for the Southern
District of West Virginia issued an injunction and order, in a case
involving unaffiliated parties, prohibiting the issuance by the
West Virginia Division of Environmental Protection of surface
mining permits which authorize the placement of excess soil in
intermittent or perennial streams.  On October 29, 1999, the
District Court stayed the effect of its order pending appeal of
this case to the U.S. Fourth Circuit Court of Appeals.  Although
management is unable to predict the effect of this decision on AEP
System operations, the decision could have, among other things, a
substantial adverse impact on the supply of coal from West Virginia
to APCo's generating plants.

    Reference is made to page 29 of the 1998 10-K and page II-3 of
the Quarterly Report on Form 10-Q for the quarter ended June 30,
1999 for a discussion of ambient air quality standards attainment.
On October 29, 1999, the U.S. Court of Appeals for the District of
Columbia Circuit issued panel and en banc decisions in this matter.
The panel granted rehearing regarding that portion of its
underlying decision relating to implementation of a secondary air
quality standard for ozone.  The panel modified its order without
briefing or oral argument.  The panel rejected the U.S.
Environmental Protection Agency's ("Federal EPA") request for
rehearing on the balance of its decision.  The full court (two
judges abstaining) rejected Federal EPA's request for rehearing en
banc by a plurality.  Federal EPA has 90 days within which to
petition the U.S. Supreme Court to hear an appeal.




                               II-1

    Reference is made to page 33 of the 1998 10-K, pages II-1 and
II-2 of the Quarterly Report on Form 10-Q for the quarter ended
March 31, 1999, and pages II-3 and II-4 of the Quarterly Report on
Form 10-Q for the quarter ended June 30, 1999, for a discussion of
an investigation by Federal EPA under Section 114 of the Clean Air
Act focused on assessing compliance with the New Source Review and
New Source Performance Standard provisions.

    In October 1999, Federal EPA, Region V, issued a request
seeking documents and information regarding capital and maintenance
expenditures at Conesville Plant and, in addition, Federal EPA,
Region III, issued such a request for Amos, Kanawha River, Kammer
and Clinch River plants.  Federal EPA, Region III, has made site
visits to the four plants identified in its request.  In November
1999, Federal EPA, Region V, issued an additional request for
Conesville, Picway, Muskingum River and Cardinal plants.

    For a discussion of a complaint filed by the U.S. Department
of Justice and a Notice of Violation issued by Federal EPA, see
AEP's Management's Discussion and Analysis of Results of Operations
and Financial Condition.

Item 6. Exhibits and Reports on Form 8-K.

    (a) Exhibits:

        AEP, APCo and OPCo

            Exhibit 10(a) - AEP System Excess Benefit Plan,
            Amended and Restated as of August 1, 1999.

            Exhibit 10(b)  -  AEP System Supplemental Savings
            Plan, Amended and Restated as of November 1, 1999.

        APCo, CSPCo, I&M, KEPCo and OPCo

            Exhibit 12 - Statement re: Computation of Ratios.

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

            Exhibit 27 - Financial Data Schedule.

    (b) Reports on Form 8-K:


Company Reporting
Date of Report
Item Reported


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


                        September 15,
                              1999


Item 5. Other Events









                               II-2
<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, 1999













                               II-3
<PAGE>
<PAGE>
                          EXHIBIT INDEX

                                                            Page
American Electric Power System
  Supplement Savings Plan
  Amended and Restated as of November 1, 1999. . . .  . . . EX-1

American Electric Power System
  Excess Benefit Plan
  Amended and Restated as of August 1, 1999 . . . . . . . . EX-10












































                               II-4

<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER SYSTEM
SUPPLEMENTAL SAVINGS PLAN

          AMENDED AND RESTATED AS OF NOVEMBER 1, 1999

                           ARTICLE I

                  Purposes and Effective Date

    1.1  The American Electric Power System Supplemental Savings
Plan is established to provide to eligible employees a tax-deferred savings
opportunity otherwise not available to them
under the terms of the American Electric Power System Employees
Savings Plan because of contribution restrictions imposed by the
Internal Revenue Code.

    1.2  The effective date of the American Electric Power
System Supplemental Savings Plan is January 1, 1994 and the
effective date of the Amended and Restated American Electric
Power System Supplemental Savings Plan is November 1, 1999.

                           ARTICLE II

                          DEFINITIONS


    2.1  "Account" means the separate memo account established
and maintained by the Company or the recordkeeper employed by the
Company to record Contributions allocated to a Participant's
Account and to record any related Investment Income on the Fund
or Funds selected by the Participant.

    2.2  "Applicable Federal Rate" means 120% of the applicable
federal long-term rate, with monthly compounding (as prescribed
under Section 1274(d) of the Code), published for the December
immediately prior to the Plan year.

    2.3  "Code" means the Internal Revenue Code of 1986, as
amended from time to time.

    2.4  "Committee" means the Employee Benefit Trusts Committee
as established by the Board of Directors of American Electric
Power Service Corporation.

    2.5  "Compensation" means a Participant's regular base
salary or wage including any salary or wage reductions made
pursuant to sections 125 and 402(e)(3) of the Code and
contributions to this Plan, and excluding bonuses (such as but
not limited to project bonuses and sign-on bonuses), performance
pay awards, severance pay, relocation payments, or any other form
of additional compensation that is not considered to be part of
base salary or base wage.



                               EX-1
   2.6  "Company" means the American Electric Power Service
Corporation and its subsidiaries and affiliates.

    2.7  "Company Contributions" means the matching
contributions made by the Company pursuant to section 3.2.

    2.8  "Contributions" means, as the context may require,
Participant Contributions and Company contributions.

    2.9  "Corporation" means the American Electric Power
Company, Inc., a New York corporation.

    2.10  "Eligible Employee" means an employee of the Company
whose compensation is in excess of the limits imposed by section
401(a)(17) of the Code.

    2.11  "ERISA" means the Employee Retirement Income Security
Act of 1974, as amended from time to time.

    2.12  "Fund" means the investment options made available to
participants in the Savings Plan and includes the Interest
Bearing Account.

    2.13  "Investment Income" means with respect to Participant
Contributions and Company Contributions the earnings, gains and
losses derived from the investment of such Contributions in a
Fund or Funds.

    2.14  "Interest Bearing Account" means an investment option
to be made available to Participants in this Plan in which the
Contributions invested in this option are credited with interest
at the Applicable Federal Rate.

    2.15  "Participant" means an Eligible Employee who has
executed a Salary Reduction Agreement.

    2.16  "Participant Contributions" means contributions made
by the Participant pursuant to an executed Salary Reduction
Agreement subject to the Participant Contribution limits
contained in section 3.1.

    2.17  "Plan" means the American Electric Power System
Supplemental Savings Plan.

    2.18  "Plan Year" means the calendar year commencing each
January 1 and ending each December 31.

    2.19  "Salary Reduction Agreement" means an agreement
between the Company and the Participant in which the Participant
elects to reduce his or her Compensation for the Plan Year and
the Company agrees to treat the amount of the salary reduction as
a Participant Contribution to this Plan.




                               EX-2
 2.20  "Savings Plan" means the American Electric Power
System Employees Savings Plan, a plan qualified under section
401(a) of the Code, as in effect from time to time.

                          ARTICLE III

                         CONTRIBUTIONS

    3.1  A Participant may elect to make Participant
Contributions by executing a Salary Reduction Agreement.  All
Participant Contributions (i) shall be made by payroll deductions
at the end of each payroll period, (ii) shall be based upon the
Compensation the Participant received during such payroll period,
and (iii) shall commence as soon as practicable after the
Participant completes and delivers to the Committee a Salary
Reduction Agreement.  Participant Contributions are to be made in
multiples of one (1) whole percentage of Compensation, not to
exceed 17 percent of Compensation for any payroll period or Plan
Year.  The maximum Participant Contribution for any Plan Year
shall not exceed the difference between (a) the Participant's
Compensation for the Plan Year times 17 percent and (b)  the
aggregate amount of the Participant's Before-Tax and After-Tax
contributions to the Savings Plan.

    3.2  Subject to the limitation contained in section 3.3, the
Company shall be deemed to contribute to the Plan on behalf of
each Participant an amount equal to 50% of the amount, not in
excess of 6% of a Participant's Compensation, contributed to the
Plan by the Participant.

    3.3  The amount of Company Contributions deemed to be
contributed to the Plan on behalf of a Participant in combination
with contributions made by the Company to the Savings Plan on
behalf of the Participant, shall, in the aggregate be equal to
the lesser of (a) 50% of the Participant Contributions made by
the Participant to this Plan and the Savings Plan, or (b) 3% of
the Participant's Compensation.  If the aggregate contributions
exceed the lesser limitation, Company Contributions credited to
the Participant's Account shall be reduced until the aggregate
Company Contributions made under both the Savings Plan and this
Plan do not exceed the limitation.

    3.4  An Eligible Employee who becomes a Participant after
the start of a Plan Year due to an increase in the Eligible
Employee's Compensation or the Eligible Employee is first
employed after the start of the Plan Year, the limitations
described in sections 3.1 and 3.2 above shall apply to the
Compensation earned and Contributions made on and after the date
the Eligible Employee becomes a Participant.







                               EX-3

<PAGE>
                           ARTICLE IV

                  INVESTMENT OF CONTRIBUTIONS

    4.1  Participant Contributions and Company Contributions
shall be invested in the Funds selected by the Participant.  The
Participant may change the selected Funds by notifying the
Company or the recordkeeper retained by the Company.  Any change
in the Funds selected by the Participant shall be implemented as
soon as practicable.

    4.2  A Participant may elect to transfer all or a portion of
the Contributions from any Fund or Funds to any other Fund or
Funds by giving notice to the Company or the recordkeeper
retained by the Company.  Transfers between Funds may be made in
any whole percentage or dollar amounts and shall be implemented
as soon as possible.

    4.3  The Funds shall be valued daily at their fair market
value and each Participant's Account shall be valued daily at its
fair market value.  The fair market value calculation for a
Participant's Account shall be made after all Contributions,
withdrawals, distributions, Investment Income and transfers for
the day are recorded.

    4.4  The Plan is an unfunded non-qualified deferred
compensation plan and therefore the Contributions credited to a
Participant's Account and the investment of those Contributions
in the Fund or Funds selected by the Participant are memo
accounts that represent general, unsecured liabilities of the
Company payable exclusively out of the general assets of the
Company.

                           ARTICLE V

           ELECTION, DISTRIBUTIONS AND BENEFICIARIES

    5.1  In order for an election to make Participant
Contributions to be effective for any given Plan Year, the
Participant must deliver a signed Salary Reduction Agreement to
the Committee no later than December 31 of the year preceding the
Plan Year as to which the election is to take effect, or if an
employee becomes an Eligible Employee after the start of the Plan
Year the election must be made within 30 days after the employee
becomes an Eligible Employee.  The Salary Reduction Agreement
shall remain in force as to the Plan Year for which it is
delivered and for each subsequent Plan Year until it is revoked
by a new Salary Reduction Agreement.  Notwithstanding any other
provision of the Plan to the contrary, no election shall be
effective to defer under the Plan any Compensation which is
earned by the Participant on or before the date upon which the
signed Salary Reduction Agreement is delivered to the Committee.
The Salary Reduction Agreement and any revocation thereof shall
contain such information as may be reasonably required by the
Committee and shall be executed at the time and in the manner
prescribed by the Committee.
                               EX-4

   5.2  Upon a Participant's termination of employment for any
reason other than death, all amounts which are credited to the
Participant's Account shall be distributed to the Participant in
the form of (1) a single lump-sum payment when the Participant's
employment is terminated or at the end of the post-termination
deferral period selected by the Participant, or (2) in
approximately equal annual or semi-annual installment payments
over not less than two or more than ten years commencing when the
Participant's employment is terminated or at the end of the
post-termination deferral period selected by the Participant.
A post-termination deferral shall be for a period of at least one year
but not more then five years from the date the Participant's
employment is terminate.  The Participant's distribution election
shall be made when the Participant first elects to participate in
the Plan.  The Participant may amend or revoke the distribution
election at any time prior to the Participant's termination of
employment, but any such amendment or revocation must be made at
least twelve months prior to the initial distribution.  If the
Participant does not elect a post-termination deferral, the
distribution of a lump-sum payment or the first installment
payment shall be made within 120 days after the Participant's
termination of employment.  If the Participant elected a post-termination
deferral, the lump-sum payment or the first
installment payment shall be made within 120 days after the end
of the deferral period.  If the Participant elects a post-termination
deferral or elects installment payments, the
Participant shall be eligible to invest the remaining balance in
the Participant's Account as provided in section 4.2.

    5.3  Upon a Participant's death prior to termination of
employment or prior to the complete distribution of the
Participant's Account, all amounts credited to the Participant's
Account shall be distributed to (a) the Participant's named
beneficiary, or (b) if the named beneficiary predeceases the
Participant or if the Participant did not name a beneficiary to
the Participant's estate.  Distributions to the named beneficiary
shall be in the form of (1) a single lump-sum payment or (2) in
approximately equal annual or semi-annual installment payments
over not less than two nor more then ten years as elected by the
beneficiary.  The beneficiary's distribution election must be
made within 90 days of the Participant's date of death.  If an
election is not made, the beneficiary shall receive a lump-sum
payment.  The distribution of a lump-sum payment or the first
installment payment to a beneficiary shall be made within 90 days
after the beneficiary makes or fails to make a distribution
election.  In the event the beneficiary elects installment
payments, the beneficiary shall be eligible to invest the
remaining balance in the Account as provided in section 4.2 as if
the beneficiary is a Participant.  In the event a beneficiary
receiving installment payments shall die prior to a complete
distribution of the Account, the remaining balance in the Account
shall be paid to the beneficiary's estate with 120 days after the
Committee is notified of beneficiary's death.  The distribution
of a lump-sum payment to the Participant's estate shall be made
within 120 days after the Participant's date of death.

                               EX-5
    5.4  Each Participant shall have the right to designate a
beneficiary or beneficiaries who shall receive the balance of the
Participant's Account if the Participant dies prior to the
complete distribution of the Participant's Account.  Any
designation, or change or rescission thereof, shall be made in
writing by completing and furnishing to the Committee the
appropriate beneficiary form prescribed by the Committee.  The
last designation of beneficiary received by the Committee prior
to the death of the Participant shall control.

                           ARTICLE VI

                    TAXES AND TAX TREATMENT

    6.1  Each Participant agrees that as a condition of
participation in the Plan, the Company may withhold federal,
state and local income taxes, Social Security taxes and Medicare
Taxes from any distribution hereunder to the extent that such
taxes are then payable.

    6.2   The adoption and maintenance of the Plan is
conditioned upon (1) the applicability of section 451(a) of the
Code to the Participant's recognition of gross income as a result
of participation herein, (2) the fact that the Participants will
not recognize gross income as a result of participation in the
Plan unless and until and then only to the extent that
distributions are received, (3) the applicability of section
404(a)(5) of the Code to the deductibility of the amounts
distributed to the Participants hereunder, (4) the fact that the
Company will not receive a deduction for amount credited to any
Account unless and until and then only to the extent that amounts
are actually distributed and (5) the inapplicability of the
provisions of Titles 2, 3, and 4 of ERISA.  If the Internal
Revenue Service, Department of Labor or any court of competent
jurisdiction determines or finds as a fact or legal conclusion
that any of the above conditions is untrue and issues an
assessment, determination, opinion or report to such effect, or
if in the opinion of counsel to the Company any one of the above
assumptions is incorrect, then the Company shall have the option
to terminate this Plan as provided in section 8.1.

                          ARTICLE VII

                         Administration

    7.1  The Committee shall (i) administer and interpret the
terms and conditions of the Plan, (ii) establish reasonable
procedures with which Participants must comply to exercise any
right established hereunder, and (iii) be permitted to delegate
its responsibilities or duties hereunder to any person or entity.
The rights and duties of the Participants and all other persons
and entities claiming an interest under the Plan are subject to,
and governed by, such acts of administration, interpretation,
procedure and delegation.


                               EX-6

<PAGE>
    7.2  The Committee may employ agents, attorneys,
accountants, or other persons and allocate or delegate to them
powers, rights, and duties all as the Committee may consider
necessary or advisable to properly carry out the administration
of the Plan.
    7.3  The Company shall maintain, or cause to be maintained,
records showing the individual credit balances of each
Participant's Account.  Each Participant shall be furnished with
quarterly statements setting forth the value of the total credits
to the Participant's Account.

                          ARTICLE VIII

                    Amendment or Termination

    8.1  The Company intends to continue the Plan indefinitely
but reserves the right to modify the Plan from time to time, or
to terminate the Plan entirely or to direct the permanent
discontinuance or temporary suspension of Contributions under the
Plan; provided that no such modification, termination,
discontinuance or suspension shall affect or otherwise deprive a
Participant or beneficiary of any distributions to which they may
be entitled under the Plan.

                           ARTICLE IX

                         Miscellaneous

    9.1  Nothing in the Plan shall interfere with or limit in
any way the right of the Company to terminate any Participant's
employment at any time, nor confer upon a Participant any right
to continue in the employ of the Company.

    9.2  In the event the Committee shall find that a
Participant or beneficiary is unable to care for his or her
affairs because of illness or accident, the Committee may direct
that any payment due the Participant or the beneficiary be paid
to the duly appointed legal representative of the Participant or
beneficiary, and any such payment so made shall be a complete
discharge of the liabilities of the Plan and the Company.

    9.3  The Plan shall be construed and administered according
to the laws of the State of Ohio.

                           ARTICLE X

                       Change In Control

    10.1    Notwithstanding any provisions of the Plan to the
contrary, if a Change in Control, as defined in Section 10.2, of
the Corporation occurs, all benefits accrued as of the date of
the Change in Control shall be fully vested and non-forfeitable.




                               EX-7

<PAGE>
    10.2     A "Change in Control" of the Corporation shall be
deemed to have occurred if (i) any "person" or "group" (as such
terms are used in Sections 13(d) and 14(d) of the Securities
Exchange Act of 1934 ("Exchange Act")), other than any company
owned, directly or indirectly, by the shareholders of the
Corporation in substantially the same proportions as their
ownership of stock of the Corporation or a trustee or other
fiduciary holding securities under an employee benefit plan of
the Corporation, becomes the "beneficial owner" (as defined in
Rule 13d-3 under the Exchange Act), directly or indirectly, of
more than 25 percent of the then outstanding voting stock of the
Corporation, (ii) during any period of two consecutive years,
individuals who at the beginning of such period constitute the
Board, together with any new Directors (other than a director
nominated by a person (x) who has entered into an agreement with
the Corporation to effect a transaction described in Section
10.2(i), (iii) or (iv) or (y) who publicly announces an intention
to take or to consider taking actions (including, but not limited
to, an actual or threatened proxy contest) which if consummated
would constitute a Change In Control) whose election or
nomination for election was approved by a vote of at least two-thirds of the
Directors then still in office who were either
Directors at the beginning of the period or whose election or
nomination for election was previously so approved, cease for any
reason to constitute at least a majority of the Board; or (iii)
the consummation of a merger or consolidation of the Corporation
with any other entity, other than a merger or consolidation which
would result in the voting securities of the Corporation
outstanding immediately prior thereto continuing to represent
(either by remaining outstanding or by being converted into
voting securities of the surviving entity) at least 50 percent of
the total voting power represented by the voting securities of
the Corporation or such surviving entity outstanding immediately
after such merger or consolidation; or (iv) the shareholders of
the Corporation approve a plan of complete liquidation of the
Corporation, or an agreement for the sale or disposition by the
Corporation (in one transaction or a series of transactions) of
all or substantially all of the Corporation's assets.

    Notwithstanding the foregoing, a Change in Control shall not
be deemed to occur as a result of the consummation of the
transactions contemplated in the Agreement and Plan of Merger by
and among the Corporation, Augusta Acquisition Corporation and
Central and South West Corporation dated as of December 21, 1997,
nor thereafter as a result of any event in (i) or (iii) above, if
Directors who were members of the Board prior to such event
continue to constitute a majority of the Board after such event.

    For purposes of this Section 10.2, "Board" shall mean the
Board of Directors of the Corporation, and "Director" shall mean
an individual who is a member of the Board.





                               EX-8
                           ARTICLE XI

                        Claims Procedure

    11.1  If a Participant makes a written request alleging a
right to receive benefits under the Plan or alleging a right to
receive an adjustment in benefits being paid under the Plan, the
Committee shall treat it as a claim for benefits.  All claims for
benefits under the Plan shall be sent to the Committee and must
be received within 30 days after the Participant's termination of
employment.  If the Committee determines that any Participant who
has claimed a right to receive benefits, or different benefits,
under the Plan is not entitled to receive all or any part of the
benefits claimed, it will inform the claimant in writing of its
determination and the reasons therefor in terms calculated to be
understood by the claimant.  The notice will be sent within 90
days of the claim unless the Committee determines additional
time, not exceeding 90 days, is needed.  The notice shall make
specific reference to the pertinent Plan provisions on which the
denial is based, and describe any additional material or
information, if any, necessary for the claimant to perfect the
claim and the reason any such addition material or information is
necessary.  Such notice shall, in addition, inform the claimant
what procedure the claimant should follow to take advantage of
the review procedures set forth below in the event the claimant
desires to contest the denial of the claim.  The claimant may
within 90 days thereafter submit in writing to the Committee a
notice that the claimant contests the denial of the claim by the
Committee and desires a further review.  The Committee shall
within 60 days thereafter review the claim and authorize the
claimant to appear personally and review pertinent documents and
submit issues and comments relating to the claim to the persons
responsible for making the determination on behalf of the
Committee.  The Committee will render its final decision with
specific reasons therefore in writing and will transmit it to the
claimant within 60 days of the written request for review, unless
the Committee deterines additional time, not exceeding 60 days,
is needed, and so notifies the claimant.  If the Committee fails
to respond to a claim filed in accordance with the foregoing
within 60 days or any such extended period, the Committee shall
be deemed to have denied the claim.















                               EX-9

<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER SYSTEM
EXCESS BENEFIT PLAN

AMENDED AND RESTATED AS OF AUGUST 1, 1999

                           ARTICLE I

                  Purposes and Effective Date


    1.1  The American Electric Power System Excess Benefit Plan
is established to provide Supplemental Retirement Benefits for
eligible employees whose retirement benefits from the American
Electric Power System Retirement Plan are restricted due to
limitations imposed by provisions of the Internal Revenue Code or
who are entitled to Supplemental Retirement Benefits under the
terms of an employment agreement between the eligible employee
and an employer.

    1.2  The effective date of the Excess Benefit Plan is
January 1, 1990 and the effective date of this amended and
restated Plan is July 1, 1999.

                           ARTICLE II

                          Definitions

    2.1  "Accredited Service" means the period of time taken
into account under the terms of the Retirement Plan for the
purpose of computing a Retirement Plan benefit.

    2.2  "Base Compensation" means a Participant's regular base
salary or wage including any salary or wage reductions made
pursuant to sections 125 and 402(e)(3) of the Code and
contributions to the American Electric Power System Supplemental
Savings Plan; and excluding bonuses (such as but not limited to
project bonuses and sign-on bonuses), performance pay awards,
severance pay, relocation payments, or any other form of
additional compensation that is not considered to be part of base
salary or base wage.

    2.3  "Code" means the Internal Revenue Code of 1986, as
amended from time to time.
    2.4  "Committee" means the Employee Benefit Trusts
Committee.

    2.5  "Company" means the American Electric Power Service
Corporation and its subsidiaries and affiliates who adopt the
Excess Benefit Plan.

    2.6  "Corporation" means the American Electric Power
Company, Inc., a New York corporation, and its affiliates and
subsidiaries.

                              EX-10

<PAGE>
    2.7  "Employment Contract" means a contract between the
Company and a Participant that provides the Participant with a
non-qualified retirement benefit.

    2.8  "ERISA" means the Employee Retirement Income Security
Act of 1974 as amended from time to time.

    2.9  "Excess Benefit Plan" means the American Electric Power
System Excess Benefit Plan, as amended or restated from time to
time.

    2.10  "Incentive Compensation" means incentive compensation
earned by a Participant under the terms of the Senior Officer
Incentive Compensation Plan, the Management Incentive
Compensation Plan, or incentive compensation to be included
pursuant to the terms of an Employment Contract.  An Incentive
Compensation award, the payment of which is deferred according to
the terms of the plan or by the election of the Participant,
shall be deemed earned at the end of the Plan Year for the
Incentive Compensation Plan.

    2.11  "Lump Sum Benefit" means the present value of the
difference between the Participant's Supplemental Retirement
Benefit calculated using the Retirement Plan early retirement
reduction factors from age 65 to age 55 and, if necessary,
actuarially reduced from age 55 to the date the Supplemental
Retirement Benefit is paid and the Participant's Supplemental
Retirement Benefit actuarially reduced from age 65 to the date
the Supplemental Retirement Benefit is paid; or, when applicable
for computing the pre-retirement surviving spouse annuity, the
present value of the difference between 50% of the Participant's
Supplemental Retirement Benefit calculated using the Retirement
Plan early retirement reduction factors from age 65 to age 55
and, if necessary, actuarially reduced from age 55 to the
Participant's date of death and (b) 50% of the Participant's
Supplemental Retirement Benefit actuarially reduced from age 65
to the date the Participant's date of death.

    2.12  "Maximum Benefit" means the maximum early, normal,
disability or deferred vested retirement benefit permitted by the
Code to be paid to a Participant from the Retirement Plan upon
the Participant's early, normal, disability or deferred
retirement or the pre-retirement surviving spouse annuity
permitted by the Code to be paid to the Surviving Spouse upon the
death of the Participant.











                              EX-11

<PAGE>
    2.13  "Participant" means any exempt salaried employee of
the Company who is a participant in the Retirement Plan, and (i)
whose base salary or base compensation exceeds the limitation of
section 401(a)(17) of the Code, or (ii) who is entitled to a
Supplemental Retirement Benefit under the terms of an Employment
Contract.  If in any Plan Year after a salaried employee becomes
a Participant, the Participant's Base Compensation is lower than
the compensation limits imposed by section 401(a)(17) of the Code
due to an increase in the 401(a)(17) limits, the Participant
shall nevertheless continue as a Participant in the Excess
Benefit Plan until the Participant terminates employment or the
Excess Benefit Plan is terminated.

    2.14  "Plan Year" means the calendar year commencing each
January 1 and ending each December 31.

    2.15  "Retirement Plan" means the American Electric Power
System Retirement Plan, as amended from time to time.

    2.16  "Supplemental Retirement Benefit" means the difference
between the Participant's Unrestricted Benefit and the
Participant's Maximum Benefit.

    2.17  "Surviving Spouse" means the spouse of a Participant
who is legally married to the Participant and whose marriage to
the Participant occurred at least one year prior to the earlier
of the Participant's termination of employment or death.

    2.18  "Unrestricted Benefit" means the early, normal,
disability or deferred vested retirement benefit payable to a
Participant upon a Participant's early, normal, disability or
deferred vested retirement or the pre-retirement surviving
annuity payable to the Surviving Spouse upon the death of the
Participant under the terms of the Retirement Plan assuming (i)
the Code restrictions on benefits that can be provided by the
Retirement Plan are not applicable and (ii) the compensation upon
which the benefit is based is the Participant's Base Compensation
and Incentive Compensation, or the non-qualified retirement
benefit provided for in an Employment Agreement.

                          ARTICLE III

                            Benefits

    3.1  Upon a Participant's normal retirement, in accordance
with the terms of the Retirement Plan, the Participant shall be
entitled to a Supplemental Retirement Benefit reduced by any
qualified or non-qualified retirement benefits the Participant is
entitled to receive from any prior employer as identified in an
Employment Contract.






                              EX-12
    3.2  Upon a Participant's early retirement, in accordance
with the terms of the Retirement Plan, the Participant shall be
entitled to a Supplemental Retirement Benefit, adjusted by the
early retirement factors contained in the Retirement Plan,
reduced by any qualified or non-qualified retirement benefits the
Participant is entitled to receive from any prior employer as
identified in an Employment Contract.

    3.3  Upon a Participant's termination of employment prior to
qualifying for early retirement under the terms of the Retirement
Plan, the Participant shall be entitled to a Supplemental
Retirement Benefit that is adjusted in accordance with the
reductions specified in the Retirement Plan for deferred vested
Retirement Plan participants reduced by any qualified or non-qualified
retirement benefits the Participant is entitled to
receive from any prior employer as identified in an Employment
Contract.

    3.4  A Participant whose employment is terminated prior to
age 55 due to a restructuring, consolidation or downsizing of the
Company and who, at the time of termination, has (i) completed 25
or more years of Accredited Service under the terms of the
Retirement Plan or (ii) has attained age 50 and has completed 10
or more years of Accredited Service under the terms of the
Retirement Plan shall be entitled to an early retirement
Supplemental Retirement Benefit as described in section 3.3 above
and a Lump Sum Benefit, the sum of which shall be reduced by any
qualified or non-qualified retirement benefits the Participant is
entitled to receive from any prior employer as identified in an
Employment Contract.

                           ARTICLE IV

                     Spousal Death Benefits

    4.1  Upon the death of a Participant prior to the
Participant's early or normal retirement as provided under the
terms of the Retirement Plan, the Surviving Spouse shall be
entitled to a Supplemental Retirement Benefit reduced by any
qualified or non-qualified retirement benefits the Surviving
Spouse is entitled to receive from the Participant's prior
employer or employers as identified in an Employment Contract.

    4.2  Upon the death of the Participant after the
Participant's early or normal retirement under the terms of the
Retirement Plan, the Surviving Spouse shall be entitled to a
Supplemental Retirement Benefit equal to the survivor annuity
option elected by the Participant at the time of the
Participant's retirement, as provided in section 5.1, reduced by
any qualified or non-qualified retirement benefits the Surviving
Spouse is entitled to receive from the Participant's prior
employer or employers as identified in an Employment Contract



                              EX-13

<PAGE>
    4.3  Upon the death of a Participant described in section
3.4 prior to the Participant's election to commence benefits, the
Surviving Spouse shall be entitled to a Supplemental Retirement
Benefit that would be paid to the Surviving Spouse of a
Participant described in section 3.3 and shall be entitled to a
Lump Sum Benefit the sum of which is to be reduced by any
qualified or non-qualified retirement benefits the Surviving
Spouse is entitled to receive from the Participant's prior
employer or employers as identified in an Employment Contract.

                           ARTICLE V

          Payment of Supplemental Retirement Benefits

    5.1  The Participant's election under the Retirement Plan of
a single life annuity, a 50% joint and survivor annuity, or an
optional form of payment (with the valid consent of the
Participant's spouse where required under the terms of the
Retirement Plan) shall be deemed to be the election made by the
Participant for the Supplemental Retirement Benefit payable under
the Excess Benefit Plan.

    5.2  The payment of a Supplemental Retirement Benefit shall
commence at the same time benefit payments from the Retirement
Plan commence.

    5.3   A Participant described in section 3.4, may elect to
commence payments of the Participant's Supplemental Retirement
Benefit as of the first day of any month following the
Participant's termination of employment, provided that the
Participant also elects to receive retirement benefits from the
Retirement Plan as of the same date. Supplemental Retirement
Benefits that commence prior to age 55 shall be reduced
actuarially from age 55 to the Participant's age at the time the
Supplemental Retirement Benefit payments commence.  The Lump Sum
Benefit payable to the Participant shall be calculated and paid
as of the date the Participant elects to receive payment of the
Supplemental Retirement Benefits.

                           ARTICLE VI

                         Administration

    6.1  The Committee shall administer the Excess Benefit Plan.
The Committee shall have the authority to interpret the Excess
Benefit Plan and to prescribe, amend and rescind rules and
regulations relating to the administration of the Excess Benefit
plan, and all such interpretations, rules and regulations shall
be conclusive and binding on all Participants.

    6.2  The Committee may employ agents, attorneys,
accountants, or other persons and allocate or delegate to them
powers, rights, and duties all as the Committee may consider
necessary or advisable to properly carry out the administration
of the Excess Benefit Plan.

                              EX-14

                          ARTICLE VII

                    Amendment or Termination

    7.1  The Company intends the Excess Benefit Plan to be
permanent but reserves the right to amend or terminate the Excess
Benefit Plan when, in the sole opinion of the Company, such
amendment or termination is advisable.  Any such amendment or
termination shall be made pursuant to a resolution of the Board
of Directors of the Company.

    7.2  No amendment or termination of the Excess Benefit Plan
shall directly or indirectly deprive any current or former
Participant or Surviving Spouse of all or any portion of any
Supplemental Retirement Benefit which commenced prior to the
effective date of such amendment or termination or which would be
payable if the Participant terminated employment for any reason,
including death, on such effective date.

                          ARTICLE VIII

                         Miscellaneous

    8.1  Nothing in this Excess Benefit Plan shall interfere
with or limit in any way the right of the Company to terminate
any Participant's employment at any time, nor confer upon a
Participant any right to continue in the employ of the Company.

    8.2  In the event the Committee shall find that a
Participant or Surviving Spouse is unable to care for his or her
affairs because of illness or accident, the Committee may direct
that any payment due the Participant or the Surviving Spouse be
paid to the duly appointed legal representative of the
Participant or Surviving Spouse, and any such payment so made
shall be a complete discharge of the liabilities of the Excess
Benefit Plan.

    8.3  Except as otherwise expressly provided herein, all
terms, conditions and actuarial assumptions of the Retirement
Plan applicable to benefits payable under the terms of the
Retirement Plan shall also be applicable to the Supplemental
Retirement Benefits paid under the terms of the Excess Benefit
Plan.

    8.4  The Supplemental Retirement Benefits paid under the
Excess Benefit Plan shall not be funded, but shall constitute
liabilities of the Company to be paid out of general corporate
assets.  Nothing contained in the Excess Benefit Plan shall
constitute a guaranty by the Company or any other entity or
person that the assets of the Company will be sufficient to pay
any benefit hereunder.

    8.5  The Excess Benefit Plan shall be construed and
administered according to the laws of the State of Ohio.


                              EX-15
                          ARTICLE IX

                       Change In Control

    9.1 Notwithstanding any provisions of the Excess Benefit
Plan to the contrary, if a Change in Control, as defined in
Section 9.2, of the Corporation occurs, all Supplemental
Retirement Benefits accrued as of the date of the Change in
Control shall be fully vested and non-forfeitable.

    9.2  A "Change in Control" of the Corporation shall be
deemed to have occurred if (i) any "person" or "group" (as such
terms are used in Sections 13(d) and 14(d) of the Securities
Exchange Act of 1934 ("Exchange Act")), other than any company
owned, directly or indirectly, by the shareholders of the
Corporation in substantially the same proportions as their
ownership of stock of the Corporation or a trustee or other
fiduciary holding securities under an employee benefit plan of
the Corporation, becomes the "beneficial owner" (as defined in
Rule 13d-3 under the Exchange Act), directly or indirectly, of
more than 25 percent of the then outstanding voting stock of the
Corporation, (ii) during any period of two consecutive years,
individuals who at the beginning of such period constitute the
Board, together with any new Directors (other than a director
nominated by a person (x) who has entered into an agreement with
the Corporation to effect a transaction described in Section
9.2(i), (iii) or (iv) or (y) who publicly announces an intention
to take or to consider taking actions (including, but not limited
to, an actual or threatened proxy contest) which if consummated
would constitute a Change In Control) whose election or
nomination for election was approved by a vote of at least two-thirds of
the Directors then still in office who were either
Directors at the beginning of the period or whose election or
nomination for election was previously so approved, cease for any
reason to constitute at least a majority of the Board; or (iii)
the consummation of a merger or consolidation of the Corporation
with any other entity, other than a merger or consolidation which
would result in the voting securities of the Corporation
outstanding immediately prior thereto continuing to represent
(either by remaining outstanding or by being converted into
voting securities of the surviving entity) at least 50 percent of
the total voting power represented by the voting securities of
the Corporation or such surviving entity outstanding immediately
after such merger or consolidation; or (iv) the shareholders of
the Corporation approve a plan of complete liquidation of the
Corporation, or an agreement for the sale or disposition by the
Corporation (in one transaction or a series of transactions) of
all or substantially all of the Corporation's assets.








                              EX-16

   Notwithstanding the foregoing, a Change in Control shall not
be deemed to occur as a result of the consummation of the
transactions contemplated in the Agreement and Plan of Merger by
and among the Corporation, Augusta Acquisition Corporation and
Central and South West Corporation dated as of December 21, 1997,
nor thereafter as a result of any event in (i) or (iii) above, if
Directors who were members of the Board prior to such event
continue to constitute majority of the Board after such event.

    For purposes of this Section 9.2, "Board" shall mean the
Board of Directors of the Corporation, and "Director" shall mean
an individual who is a member of the Board.

                           ARTICLE X

                        Claims Procedure

    10.1  If a Participant makes a written request alleging a
right to receive benefits under the Excess Benefit Plan or
alleging a right to receive an adjustment in benefits being paid
under the Excess Benefit Plan, the Committee shall treat it as a
claim for benefits.  All claims for benefits under the Excess
Benefit Plan shall be sent to the Committee and must be received
within 30 days after the Participant's termination of employment.
If the Committee determines that any Participant who has claimed
a right to receive benefits, or different benefits, under the
Excess Benefit Plan is not entitled to receive all or any part of
the benefits claimed, it will inform the claimant in writing of
its determination and the reasons therefor in terms calculated to
be understood by the claimant.  The notice will be sent within 90
days of the claim unless the Committee determines additional
time, not exceeding 90 days, is needed.  The notice shall make
specific reference to the pertinent Excess Benefit Plan
provisions on which the denial is based, and describe any
additional material or information, if any, necessary for the
claimant to perfect the claim and the reason any such addition
material or information is necessary.  Such notice shall, in
addition, inform the claimant what procedure the claimant should
follow to take advantage of the review procedures set forth below
in the event the claimant desires to contest the denial of the
claim.  The claimant may within 90 days thereafter submit in
writing to the Committee a notice that the claimant contests the
denial of the claim by the Committee and desires a further
review.  The Committee shall within 60 days thereafter review the
claim and authorize the claimant to appear personally and review
pertinent documents and submit issues and comments relating to
the claim to the persons responsible for making the determination
on behalf of the Committee.  The Committee will render its final
decision with specific reasons therefore in writing and will
transmit it to the claimant wthin 60 days of the written request
for review, unless the Committee determines additional time, not
exceeding 60 days, is needed, and so notifies the claimant.  If
the Committee fails to respond to a claim filed in accordance
with the foregoing within 60 days or any such extended period,
the Committee shall be deemed to have denied the claim.

                              EX-17