SECURITIES AND EXCHANGE COMMISSION
                      WASHINGTON, D.C. 20549


                             FORM 10-K


(Mark One)

  <square>

  x   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
      THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]

      For the fiscal year ended December 31, 1995

   <square>TRANSITION REPORT PURSUANT TO SECTION 13 OR
      15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

      For the transition period from _____________ to ______________





COMMISSION               REGISTRANT; STATE OF INCORPORATION;    I.R.S. EMPLOYER
FILE NUMBER              ADDRESS; AND TELEPHONE NUMBER       IDENTIFICATION NO.

  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                    31-1033833
                         (An Ohio Corporation)
                         1 Riverside Plaza
                         Columbus, Ohio 43215
                         Telephone (614) 223-1000

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

  1-2680                 COLUMBUS SOUTHERN POWER COMPANY           31-4154203
                         (An Ohio Corporation)
                         215 North Front Street
                         Columbus, Ohio 43215
                         Telephone (614) 464-7700

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

  1-6858                 KENTUCKY POWER COMPANY                    61-0247775
                         (A Kentucky Corporation)
                         1701 Central Avenue
                         Ashland, Kentucky 41101
                         Telephone (800) 572-1113

  1-6543                 OHIO POWER COMPANY                        31-4271000
                         (An Ohio Corporation)
                         301 Cleveland Avenue, S.W.
                         Canton, Ohio 44702
                         Telephone (330) 456-8173



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




   Indicate by check mark whether the  registrants  (1)  have filed all reports
required to be filed by Section 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  <check-mark> .  No.    .


SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:


                                                   NAME OF EACH EXCHANGE
REGISTRANT              TITLE OF EACH CLASS         ON WHICH REGISTERED

AEP Generating 
 Company                None

American Electric       Common Stock,
 Power Company, Inc.     $6.50 par value        New York Stock Exchange

Appalachian Power       Cumulative Preferred
 Company                 Stock Voting, 
                         no par value:
                          4-1/2%                Philadelphia Stock Exchange
                          4.50%                 Philadelphia Stock Exchange
                          7.40%                 New York Stock Exchange

Columbus Southern       8-3/8% Junior Subordinated 
 Power Company            Deferrable Interest 
                          Debentures, Series A,
                          Due 2025              New York Stock Exchange

Indiana Michigan        Cumulative Preferred
 Power Company            Stock, Non-Voting,
                          $100 par value:
                           4-1/8%               Chicago Stock Exchange
                           7.08%                New York Stock Exchange

Kentucky Power Company  8.72% Junior Subordinated 
                         Deferrable Interest 
                         Debentures, Series A,
                         Due 2025               New York Stock Exchange

Ohio Power Company      8.16% Junior Subordinated 
                         Deferrable Interest 
                         Debentures, Series A,
                         Due 2025               New York Stock Exchange

   Indicate by check mark if disclosure of delinquent filers  with  respect  to
American Electric Power Company, Inc. and Appalachian Power Company pursuant to
Item  405 of Regulation S-K (<section>229.405 of this chapter) is not contained
herein,  and  will  not be contained, to the best of registrant's knowledge, in
the definitive proxy  statement  of  American  Electric  Power Company, Inc. or
definitive information statement of Appalachian Power Company  incorporated  by
reference  in  Part  III  of this Form 10-K or any amendment to this Form 10-K.


   Indicate by check mark if  disclosure  of  delinquent filers with respect to
Indiana Michigan Power Company or Ohio Power Company  pursuant  to  Item 405 of
Regulation S-K (<section>229.405 of this chapter) is not contained herein,  and
will not be contained, to the best of registrant's knowledge, in the definitive
information  statement  of Ohio Power Company incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K.  <check-mark>



SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:

   REGISTRANT                            TITLE OF EACH CLASS

AEP Generating Company                   None

American Electric Power Company, Inc.    None

Appalachian Power Company                None

Columbus Southern Power Company          None

Indiana Michigan Power Company           None

Kentucky Power Company                   None

Ohio Power Company                       4-1/2% Cumulative Preferred Stock,
                                         Voting, $100 par value


                         AGGREGATE MARKET VALUE   NUMBER OF SHARES
                         OF VOTING STOCK HELD     OF COMMON STOCK
                         BY NON-AFFILIATES OF     OUTSTANDING OF
                         THE REGISTRANTS AT       THE REGISTRANTS AT
                         FEBRUARY 2, 1996         FEBRUARY 2, 1996

AEP Generating 
Company                  None                             1,000
                                                    ($1,000 par value)

American Electric 
Power Company, Inc.      $8,164,000,000             186,635,000
                                                    ($6.50 par value)

Appalachian Power 
Company                  $43,000,000                 13,499,500
                                                    (no par value)

Columbus Southern 
Power Company            None                        16,410,426
                                                    (no par value)

Indiana Michigan 
Power Company            None                         1,400,000
                                                    (no par value)

Kentucky Power 
Company                  None                         1,009,000
                                                    ($50 par value)

Ohio Power 
Company                  $68,000,000                 27,952,473
                                                    (no par value)

          NOTE ON MARKET VALUE OF VOTING STOCK HELD BY NON-AFFILIATES

   All  of  the  common  stock  of  AEP  Generating  Company, Appalachian Power
Company,  Columbus  Southern  Power  Company, Indiana Michigan  Power  Company,
Kentucky Power Company and Ohio Power  Company  is  owned  by American Electric
Power  Company,  Inc.  (see Item 12 herein).  The voting stock  owned  by  non-
affiliates of (i) Appalachian  Power  Company  consists  of  552,348  shares of
Cumulative  Preferred Stock, no par value; and (ii) Ohio Power Company consists
of 862,403 shares  of  Cumulative  Preferred Stock, $100 par value. Some of the
series of Cumulative Preferred Stock  are  not regularly traded.  The aggregate
market value of the Cumulative Preferred Stock  is  based on the average of the
high and low prices on the closest trading date to February  2, 1996 for series
traded  on  the  New  York or Philadelphia Stock Exchange, or the  most  recent
reported bid prices for  those series not recently traded.  Where recent market
price information was not  available with respect to a series, the market price
for such series is based on  the  price  of  a  recently  traded series with an
adjustment related to any difference in the current yields of the two series.
<PAGE>
                      DOCUMENTS INCORPORATED BY REFERENCE

                                                            PART OF FORM 10-K
                                                           INTO WHICH DOCUMENT
   DESCRIPTION                                               IS INCORPORATED

Portions of Annual Reports of the following companies for the
   fiscal year ended December 31, 1995:                          Part II

      AEP Generating Company
      American Electric Power Company, Inc.
      Appalachian Power Company
      Columbus Southern Power Company
      Indiana Michigan Power Company
      Kentucky Power Company
      Ohio Power Company

Portions of Proxy Statement of American Electric Power
   Company, Inc., dated March 9, 1996, for Annual
   Meeting of Shareholders                                      Part III

Portions of Information Statements of the following companies
   for 1996 Annual Meeting of Shareholders, to be filed within
   120 days after December 31, 1995:                            Part III

      Appalachian Power Company
      Ohio Power Company






   THIS  COMBINED  FORM  10-K  IS  SEPARATELY FILED BY AEP GENERATING  COMPANY,
AMERICAN  ELECTRIC POWER COMPANY, INC.,  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.  EXCEPT
FOR  AMERICAN  ELECTRIC  POWER  COMPANY,  INC.,   EACH   REGISTRANT   MAKES  NO
REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.




<PAGE>
                      TABLE OF CONTENTS

                                                     PAGE
                                                     NUMBER

Glossary of Terms                                         i

PART I
  Item 1. Business                                         1
  Item 2. Properties                                      29
  Item 3. Legal Proceedings                               33
  Item 4. Submission of Matters to a Vote of Security
            Holders                                       34
  Executive Officers of the Registrants                   34

PART II
  Item 5. Market for Registrant's Common Equity and
            Related Stockholder Matters                   37
  Item 6. Selected Financial Data                         37
  Item 7. Management's Discussion and Analysis of Results
           of Operations and Financial Condition          37
  Item 8. Financial Statements and Supplementary Data     38
  Item 9. Changes in and Disagreements with Accountants
           on Accounting and Financial Disclosure         38

PART III
  Item 10. Directors and Executive Officers of the 
            Registrants                                   39
  Item 11. Executive Compensation                         40
  Item 12. Security Ownership of Certain Beneficial
            Owners and Management                         44
  Item 13. Certain Relationships and Related Transactions 45

PART IV
  Item 14. Exhibits, Financial Statement Schedules, and
            Reports on Form 8-K                           46

Signatures                                                48

Index to Financial Statement Schedules                   S-1

Independent Auditors' Report                             S-2

Exhibit Index                                            E-1
<PAGE>
                               GLOSSARY OF TERMS

   When  the  following  terms  and  abbreviations  appear  in the text of this
report, they have the meanings indicated below.

        TERM                                 MEANING

AEGCo                  AEP Generating Company, an electric utility subsidiary
                       of AEP.
AEP                    American Electric Power Company, Inc.
AEP System or 
  the System           The American Electric Power System, an integrated
                       electric utility system, owned and operated by AEP's
                       electric utility subsidiaries.
AFUDC                  Allowance for funds used during construction. Defined
                       in regulatory systems of accounts as the net cost of 
                       borrowed funds used for construction and a reasonable
                       rate of return on other funds when so used.
APCo                   Appalachian Power Company, an electric utility
                       subsidiary of AEP.
Buckeye                Buckeye Power, Inc., an unaffiliated corporation.
CCD Group              CSPCo, CG&E and DP&L.
CG&E                   The Cincinnati Gas & Electric Company, an unaffiliated
                       utility company.
Cook Plant             The Donald C. Cook Nuclear Plant, owned by I&M.
CSPCo                  Columbus Southern Power Company, an electric utility
                       subsidiary of AEP.
DOE                    United States Department of Energy.
DP&L                   The Dayton Power and Light Company, an unaffiliated
                       utility company.
Federal EPA            United States Environmental Protection Agency.
FERC                   Federal Energy Regulatory Commission (an independent
                       commission within the DOE).
I&M                    Indiana Michigan Power Company, an electric utility
                       subsidiary of AEP.
IURC                   Indiana Utility Regulatory Commission.
KEPCo                  Kentucky Power Company, an electric utility subsidiary
                       of AEP.
KPSC                   Kentucky Public Service Commission.
MPSC                   Michigan Public Service Commission.
NEIL                   Nuclear Electric Insurance Limited.
NPDES                  National Pollutant Discharge Elimination System.
NRC                    Nuclear Regulatory Commission.
Ohio EPA               Ohio Environmental Protection Agency.
OPCo                   Ohio Power Company, an electric utility subsidiary of
                       AEP.
OVEC                   Ohio Valley Electric Corporation, an electric utility
                       company in which AEP and CSPCo own a 44.2% equity 
                       interest.
PCB's                  Polychlorinated biphenyls.
PUCO                   The Public Utilities Commission of Ohio.
PUHCA                  Public Utility Holding Company Act of 1935, as amended.
RCRA                   Resource Conservation and Recovery Act of 1976, as
                       amended.
Rockport Plant         A generating plant, consisting of two 1,300,000-kilowatt
                       coal-fired generating units, near Rockport, Indiana.
SEC                    Securities and Exchange Commission.
Service Corporation    American Electric Power Service Corporation, a service
                       subsidiary of AEP.
SO{2} Allowance        An allowance to emit one ton of sulfur dioxide granted
                       under the Clean Air Act Amendments of 1990.
TVA                    Tennessee Valley Authority.
VEPCo                  Virginia Electric and Power Company, an unaffiliated
                       utility company.
Virginia SCC           State Corporation Commission of Virginia.
West Virginia PSC      Public Service Commission of West Virginia.
Zimmer or Zimmer Plant Wm. H. Zimmer Generating Station, commonly owned by
                       CSPCo, CG&E and DP&L.


                                       i
<PAGE>
                     [THIS PAGE INTENTIONALLY LEFT BLANK]
<PAGE>
PART I


Item 1.  BUSINESS



GENERAL


   AEP  was  incorporated  under  the laws of the State of New York in 1906 and
reorganized  in  1925.  It is a public  utility  holding  company  which  owns,
directly or indirectly,  all  of  the  outstanding common stock of its electric
utility and other subsidiaries.  Substantially all of the operating revenues of
AEP and its subsidiaries are derived from the furnishing of electric service.


   The service area of AEP's electric utility  subsidiaries  covers portions of
the states of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia  and  West
Virginia.  The generating and transmission facilities of AEP's subsidiaries are
physically  interconnected,  and  their operations are coordinated, as a single
integrated electric utility system.   Transmission  networks are interconnected
with extensive distribution facilities in the territories served.  The electric
utility  subsidiaries  of  AEP  have traditionally provided  electric  service,
consisting of generation, transmission and distribution, on an integrated basis
to their retail customers.  As a  result of the changing nature of the electric
business (see COMPETITION AND BUSINESS  CHANGE),  effective  January  1,  1996,
AEP's  subsidiaries  realigned  into  four  functional  business  units:  Power
Generation; Nuclear Generation; Energy Delivery; and Corporate Development.  In
addition,  the electric utility subsidiaries began to do business as  "American
Electric  Power."    The   legal   and  financial  structure  of  AEP  and  its
subsidiaries, however, did not change.


   At  December  31, 1995, the subsidiaries  of  AEP  had  a  total  of  18,502
employees.  AEP, as  such, has no employees.  The operating subsidiaries of AEP
are:


      APCO (organized  in  Virginia  in  1926)  is  engaged  in the generation,
   purchase,  transmission and distribution of electric power to  approximately
   859,000 retail  customers  in  the  southwestern  portion  of  Virginia  and
   southern  West  Virginia,  and  in  supplying electric power at wholesale to
   other electric utility companies and  municipalities  in those states and in
   Tennessee.  At December 31, 1995, APCo and its wholly owned subsidiaries had
   4,338 employees.  Among the principal industries served  by  APCo  are  coal
   mining,  primary  metals, chemicals, textiles, paper, stone, clay, glass and
   concrete products,  rubber,  plastic products and furniture.  In addition to
   its  AEP System interconnections,  APCo  also  is  interconnected  with  the
   following  unaffiliated  utility companies:  Carolina Power & Light Company,
   Duke Power Company and VEPCo.   A comparatively small part of the properties
   and business of APCo is located in  the  northeastern  end  of the Tennessee
   Valley.  APCo has several points of interconnection with TVA and has entered
   into agreements with TVA under which APCo and TVA interchange  and  transfer
   electric power over portions of their respective systems.


      CSPCO (organized in Ohio in 1937, the earliest direct predecessor company
   having  been  organized  in  1883)  is  engaged in the generation, purchase,
   transmission and distribution of electric  power  to  approximately  599,000
   customers  in  Ohio,  and  in supplying electric power at wholesale to other
   electric utilities and to municipally  owned distribution systems within its
   service area.  At December 31, 1995, CSPCo  had  2,174  employees.   CSPCo's
   service  area  is comprised of two areas in Ohio, which include portions  of
   twenty-five counties.   One area includes the City of Columbus and the other
   is a predominantly rural  area  in south central Ohio.  Approximately 80% of
   CSPCo's retail revenues are derived  from  the  Columbus  area.   Among  the
   principal  industries served are food processing, chemicals, primary metals,
   electronic machinery  and  paper  products.   In  addition to its AEP System
   interconnections,   CSPCo   also  is  interconnected  with   the   following
   unaffiliated utility companies:  CG&E, DP&L and Ohio Edison Company.


      I&M  (organized  in Indiana  in  1925)  is  engaged  in  the  generation,
   purchase, transmission  and  distribution of electric power to approximately
   537,000 customers in northern and eastern Indiana and southwestern Michigan,
   and in supplying electric power  at  wholesale  to  other  electric  utility
   companies, rural electric cooperatives and municipalities.  At December  31,
   1995,  I&M  had  3,525 employees.  Among the principal industries served are
   primary  metals,  transportation   equipment,   fabricated  metal  products,
   electrical  and  electronic  machinery,  rubber  and  miscellaneous  plastic
   products and chemicals and allied products.  Since 1975,  I&M has leased and
   operated  the  assets  of  the municipal system of the City of  Fort  Wayne,
   Indiana.   In addition to its  AEP  System  interconnections,  I&M  also  is
   interconnected  with  the following unaffiliated utility companies:  Central
   Illinois  Public  Service   Company,   CG&E,  Commonwealth  Edison  Company,
   Consumers Power Company, Illinois Power  Company, Indianapolis Power & Light
   Company,  Louisville  Gas  and  Electric Company,  Northern  Indiana  Public
   Service Company, PSI Energy Inc. and Richmond Power & Light Company.


      KEPCO (organized in Kentucky in  1919)  is  engaged  in  the  generation,
   purchase,  transmission  and distribution of electric power to approximately
   165,000 customers in an area  in eastern Kentucky, and in supplying electric
   power at wholesale to other utilities  and  municipalities  in Kentucky.  At
   December 31, 1995, KEPCo had 748 employees.  In addition to its  AEP  System
   interconnections,   KEPCo   also   is   interconnected  with  the  following
   unaffiliated  utility  companies:   Kentucky   Utilities  Company  and  East
   Kentucky Power Cooperative Inc.  KEPCo is also interconnected with TVA.


      KINGSPORT POWER COMPANY (organized in Virginia in 1917) provides electric
   service to approximately 42,000 customers in Kingsport and eight neighboring
   communities  in  northeastern Tennessee.  Kingsport  Power  Company  has  no
   generating facilities  of  its own.  It purchases electric power distributed
   to its customers from APCo.   At  December 31, 1995, Kingsport Power Company
   had 101 employees.


      OPCO (organized in Ohio in 1907 and reincorporated in 1924) is engaged in
   the generation, purchase, transmission and distribution of electric power to
   approximately 668,000 customers in  the  northwestern, east central, eastern
   and southern sections of Ohio, and in supplying  electric power at wholesale
   to  other electric utility companies and municipalities.   At  December  31,
   1995, OPCo and its wholly owned subsidiaries had 4,998 employees.  Among the
   principal  industries  served by OPCo are primary metals, rubber and plastic
   products, stone, clay, glass  and  concrete  products,  petroleum  refining,
   chemicals  and electrical and electronic machinery.  In addition to its  AEP
   System interconnections,  OPCo  also  is  interconnected  with the following
   unaffiliated  utility companies:  CG&E, The Cleveland Electric  Illuminating
   Company,  DP&L,   Duquesne   Light   Company,  Kentucky  Utilities  Company,
   Monongahela Power Company, Ohio Edison  Company,  The  Toledo Edison Company
   and West Penn Power Company.


      WHEELING  POWER  COMPANY  (organized  in  West  Virginia  in   1883   and
   reincorporated  in  1911)  provides electric service to approximately 41,000
   customers  in  northern  West  Virginia.   Wheeling  Power  Company  has  no
   generating facilities of its own.   It  purchases electric power distributed
   to its customers from OPCo.  At December  31,  1995,  Wheeling Power Company
   had 135 employees.


   Another  principal electric utility subsidiary of AEP is  AEGCo,  which  was
organized in Ohio in 1982 as an electric generating company.  AEGCo sells power
at wholesale to I&M, KEPCo and VEPCo.  AEGCo has no employees.


   See Item 2  for information concerning the properties of the subsidiaries of
AEP.


   The Service Corporation  provides  accounting,  administrative,  information
systems, engineering, financial, legal, maintenance and other services  at cost
to  the  AEP  System  companies.   The executive officers of AEP and its public
utility subsidiaries are all employees of the Service Corporation.

REGULATION


   GENERAL


   AEP and its subsidiaries are subject  to  the broad regulatory provisions of
PUHCA administered by the SEC.  The public utility  subsidiaries'  retail rates
and  certain  other  matters  are  subject  to regulation by the public utility
commissions of the states in which they operate.   Such  subsidiaries  are also
subject  to  regulation  by the FERC under the Federal Power Act in respect  of
rates for interstate sale  at  wholesale  and  transmission  of electric power,
accounting  and  other matters and construction and operation of  hydroelectric
projects.  I&M is  subject to regulation by the NRC under the Atomic Energy Act
of 1954, as amended, with respect to the operation of the Cook Plant.


   POSSIBLE CHANGE TO PUHCA


   The provisions of  PUHCA, administered by the SEC, regulate all aspects of a
registered holding company system, such as the AEP System.  PUHCA requires that
the operations of a registered  holding  company  system be limited to a single
integrated public utility system and such other businesses as are incidental or
necessary to the operations of the system.  In addition,  PUHCA  governs, among
other  things,  financings,  sales  or  acquisitions of assets and intra-system
transactions.


   On June 20, 1995, the SEC released a report  from its Division of Investment
Management recommending a conditional repeal of PUHCA,  including its limits on
financing  and  on geographic and business diversification.   Specific  federal
authority, however,  would be preserved over access to the books and records of
registered holding company  systems,  audit  authority  over registered holding
companies  and  their  subsidiaries and oversight over affiliate  transactions.
This authority would be  transferred to the FERC.  In October 1995, legislation
was introduced in the U.S.  Senate to repeal PUHCA and transfer certain federal
authority to the FERC as recommended  in the SEC report.  If PUHCA is repealed,
registered holding company systems, including  the  AEP System, will be able to
compete in the changing industry without the constraints  of PUHCA.  Management
of AEP believes that removal of these constraints would be  beneficial  to  the
AEP System.


   PUHCA   and  the  rules  and  orders  of  the  SEC  currently  require  that
transactions  between  associated  companies  in  a  registered holding company
system be performed at cost with limited exceptions.   Over  the years, the AEP
System  has  developed  numerous  affiliated  service,  sales  and construction
relationships  and,  in some cases, invested significant capital and  developed
significant operations  in  reliance upon the ability to recover its full costs
under these provisions.  On December  28,  1994,  the SEC proposed revisions to
its rules governing transactions between associated  companies  in a registered
holding  company  system.   These  proposed revisions to the rules would  price
transactions governed by SEC rules at  a market-based price if it is lower than
cost.   In  its  June  1995  report,  the  Division  of  Investment  Management
recommended that the proposed revisions to the rules be withdrawn.


   In addition, proposals have been made for Congress to repeal PUHCA or modify
its provisions governing intra-system transactions.  The effect of possible SEC
revisions of these cost provisions or the repeal or amendment of PUHCA on AEP's
intra-system  transactions  depends  on whether  the  assurance  of  full  cost
recovery is eliminated  immediately  or  phased-in and whether it is eliminated
for  all intra-system transactions  or  only  some.   If  the  cost recovery 
assurance is eliminated immediately for all intra-system transactions,
it could have a material  adverse effect on results of operations and 
financial condition of AEP and OPCo.


   CONFLICT OF REGULATION


   Public utility subsidiaries  of AEP can be subject to regulation of the same
subject  matter  by  two or more jurisdictions.   In  such  situations,  it  is
possible that the decisions  of such regulatory bodies may conflict or that the
decision of one such body may  affect  the cost of providing service and so the
rates in another jurisdiction.  In a case  involving  OPCo,  the  U.S. Court of
Appeals for the District of Columbia held that the determination of costs to be
charged to associated companies by the SEC under PUHCA precluded the  FERC from
determining  that  such  costs were unreasonable for ratemaking purposes.   The
U.S. Supreme Court also has  held that a state commission may not conclude that
a FERC approved wholesale power  agreement is unreasonable for state ratemaking
purposes.  Certain actions that would  overturn  these  decisions  or otherwise
affect the jurisdiction of the SEC and FERC are under consideration by the U.S.
Congress  and  these  regulatory bodies.  Such conflicts of jurisdiction  often
result in litigation and,  if resolved adversely to a public utility subsidiary
of AEP, could have a material  adverse  effect  on the results of operations or
financial condition of such subsidiary or AEP.


CLASSES OF SERVICE


   The  principal  classes  of service from which the  major  electric  utility
subsidiaries of AEP derive revenues  and  the  amount  of  such  revenues (from
kilowatt-hour sales) during the year ended December 31, 1995 are as follows:
<TABLE>
<CAPTION>
                                AEGCO      APCO        CSPCO       I&M        KEPCO       OPCO    AEP SYSTEM (a)
                                                  (IN THOUSANDS)
<S>                             <C>      <C>        <C>         <C>        <C>       <C>          <C>
Retail                                            
Residential
Without Electric Heating        $ --     $ 240,385  $  329,881  $ 239,266  $ 43,938  $  277,780  $1,151,981
With Electric Heating             --       331,445     115,386    109,504    63,609     145,688     801,956

Total Residential                 --       571,830     445,267    348,770   107,547     423,468   1,953,937
Commercial                        --       284,866     371,461    256,319    58,606     257,300   1,265,776
Industrial                        --       366,329     143,162    298,256    96,647     639,177   1,606,451
Miscellaneous                     --        32,270      16,041      6,482       847       8,065      67,047

Total Retail                      --     1,255,295     975,931    909,827   263,647   1,328,010   4,893,211
Wholesale (sales for resale)    231,659    269,493      75,466    357,441    60,567     457,758     680,905

Total from KWH Sales            231,659  1,524,788   1,051,397  1,267,268   324,214   1,785,768   5,574,116
Provision for Revenue Refunds     --        (1,100)     --        --        --          --         (1,100)

Total Net of Provision for
Revenue Refunds                 231,659  1,523,688   1,051,397  1,267,268   324,214   1,785,768   5,573,016
Other Operating Revenues            136     21,351      20,465     15,889     3,930      37,229      97,314

Total Electric Operating 
Revenues                      $231,795  $1,545,039  $1,071,862 $1,283,157  $328,144 $1,822,997  $5,670,330

</TABLE>

(a) Includes revenues of other subsidiaries not shown and reflects  elimination
of intercompany transactions.

<PAGE>



SALE OF POWER


   AEP's  electric  utility subsidiaries own or lease generating stations  with
total generating capacity of 23,759 megawatts.  See Item 2 for more information
regarding the generating  stations.   They operate their generating plants as a
single interconnected and coordinated electric  utility  system  and  share the
costs  and  benefits in the AEP System Power Pool.  Most of the electric  power
generated at  these  stations  is  sold,  in  combination with transmission and
distribution  services, to retail customers of AEP's  utility  subsidiaries  in
their service territories.   These sales are made at rates that are established
by the public utility commissions  of  the  state  in  which they operate.  See
RATES.   Some  of  the  electric power is sold at wholesale  to  non-affiliated
companies.


   AEP SYSTEM POWER POOL


   APCo,  CSPCo,  I&M, KEPCo  and  OPCo  are  parties  to  the  Interconnection
Agreement, dated July  6,  1951,  as  amended  (the Interconnection Agreement),
defining  how they share the costs and benefits associated  with  the  System's
generating  plants.   This  sharing  is based upon each company's "member-load-
ratio," which is calculated monthly on the basis of each company's maximum peak
demand in relation to the sum of the maximum peak demands of all five companies
during the preceding 12 months.  In addition,  since  1995,  APCo,  CSPCo, I&M,
KEPCo and OPCo have been parties to the AEP System Interim Allowance  Agreement
which  provides,  among  other  things,  for  the  transfer of SO{2} Allowances
associated with transactions under the Interconnection Agreement.


   The following table shows the net credits or (charges)  allocated  among the
parties  under  the  Interconnection  Agreement and Interim Allowance Agreement
during the years ended December 31, 1993, 1994 and 1995:


                  1993        1994         1995(a)
                         (in thousands)

APCo           $(260,000)   $(254,000)   $(252,000)
CSPCo           (141,000)    (105,000)    (143,000)
I&M              183,000      107,000      118,000
KEPCo              1,000       12,000       23,000
OPCo             217,000      240,000      254,000


(a) Includes  credits  and  charges from allowance  transfers  related  to  the
    transactions.

   In July 1994, APCo, CSPCo,  I&M,  KEPCo and OPCo entered into the AEP System
Interim Allowance Agreement (IAA).  Reference  is  made  to  ENVIRONMENTAL  AND
OTHER  MATTERS  -  CLEAN  AIR  ACT AMENDMENTS OF 1990 for a discussion of SO{2}
Allowances.  The IAA provides for  and  governs  the  terms  of  the  following
allowance transactions among the parties which began January 1, 1995:   (1)  an
annual  reallocation  of  certain  SO{2}  Allowances initially allocated by the
Federal EPA to OPCo's Gavin Plant; (2) transfer  of SO{2} Allowances associated
with energy transactions among APCo, CSPCo, I&M, KEPCo  and OPCo, (3) a monthly
cash settlement for SO{2} Allowances consumed in connection with power sales to
non-affiliated  electric utilities; and (4) transfers of SO{2}  Allowances  for
current and future  period  compliance.   The  IAA  does  not  provide  for the
allocation  of  costs  and  proceeds  related  to the sale or purchase of SO{2}
Allowances to or from non-affiliated companies.   The  IAA  was accepted by the
FERC on December 30, 1994.


   WHOLESALE SALES OF POWER TO NON-AFFILIATES


   AEGCo,  APCo,  CSPCo,  I&M,  KEPCo and OPCo also sell electric  power  on  a
wholesale basis to non-affiliated electric utilities and power marketers.  Such
sales are either made by the AEP  System  and then allocated among APCo, CSPCo,
I&M, KEPCo and OPCo based on member-load-ratios or made by individual companies
pursuant to various long-term power agreements.   The following table shows the
amounts  contributed  to operating income of the various  companies  from  such
sales during the years ended December 31, 1993, 1994 and 1995:


                   1993(a)    1994(a)    1995(a)
                         (in thousands)

AEGCo(b)          $ 32,500   $ 30,800   $ 29,200
APCo(c)             23,600     25,000     24,100
CSPCo(c)            12,000     11,700     12,000
I&M(c)(d)           35,300     34,600     34,700
KEPCo(c)             4,900      4,800      5,000
OPCo(c)             20,700     20,000     20,200

   Total System   $129,000   $126,900   $125,200


(a) Such  sales do not include  wholesale  sales  to  full/partial  requirement
    customers of AEP System companies.  See the discussion below.
(b) All amounts  for  AEGCo  are  from sales made pursuant to a long-term power
    agreement.  See AEGCO - UNIT POWER AGREEMENTS.
(c) All amounts, except for I&M, are  from  System  sales  which  are allocated
    among  APCo, CSPCo, I&M, KEPCo and OPCo based upon member-load-ratio.   All
    System sales  made  in 1993, 1994 and 1995 were made on a short-term basis,
    except that $16,800,000,  $21,800,000 and $22,500,000, respectively, of the
    contribution to operating income  for  the total System were from long-term
    System sales.
(d) In addition to its allocation of System  sales,  the  1993,  1994  and 1995
    amounts  for  I&M  include $21,600,000, $21,600,000 and $21,000,000 from  a
    long-term agreement  to  sell 250 megawatts of power scheduled to terminate
    in 2009.

   The AEP System has long-term  system  agreements  to  sell  100 megawatts of
electric power through 1997 and to sell at times up to 200 megawatts of peaking
power  through  March 1997 to unaffiliated utilities.  In addition,  commencing
January 1996, the AEP System began supplying 205 megawatts of electric power to
an unaffiliated utility  for  15  years  and commencing September 1996, the AEP
System will begin supplying 50 megawatts of  electric  power to an unaffiliated
utility for five years.


   In addition to long-term and short-term sales, APCo,  CSPCo,  I&M, KEPCo and
OPCo  serve unaffiliated wholesale customers that are full/partial  requirement
customers.   The  aggregate maximum demand for these customers in 1995 was 574,
112,  536,  17  and 138  megawatts  for  APCo,  CSPCo,  I&M,  KEPCo  and  OPCo,
respectively.  Although  the  terms of the contracts with these customers vary,
they generally can be terminated  by  the  customer  upon  one  to  four years'
notice.  In 1995, customers gave notices of termination, effective in 1998, for
419, 5 and 67 megawatts for APCo, I&M and OPCo, respectively.


   In June 1993, certain municipal customers of APCo, who have since given APCo
notice to terminate their contracts in 1998, filed an application with the FERC
for  transmission  service  in order to reduce by 50 megawatts the power  these
customers purchase under existing  Electric  Service  Agreements  (ESAs) and to
purchase  power  from  a third party.  APCo maintains that its agreements  with
these customers are full-requirements  contracts  which  preclude the customers
from  purchasing  power  from third parties.  On February 10,  1994,  the  FERC
issued an order finding that  the  ESAs are not full requirements contracts and
that  the  ESAs  give  these  municipal  wholesale   customers  the  option  of
substituting alternative sources of power for energy purchased  from  APCo.  On
May 24, 1994, APCo appealed the February 10, 1994 order of the FERC to the U.S.
Court  of  Appeals for the District of Columbia Circuit.  On July 1, 1994,  the
FERC ordered  the  requested transmission service and granted a complaint filed
by the municipal customers directing certain modifications to the ESAs in order
to accommodate their  power  purchases  from the third party.  Following FERC's
denial of APCo's requests for rehearing,  on  December  20, 1995, APCo appealed
the  July  1,  1994  Orders to the U.S. Court of Appeals for  the  District  of
Columbia.  Effective August  1994,  these  municipal  customers  reduced  their
purchases  by  40  megawatts.  Certain of these customers further reduced their
purchases by an additional 21 megawatts effective February 1996.

TRANSMISSION SERVICES


   AEP's  electric  utility  subsidiaries  own  and  operate  transmission  and
distribution lines and  other facilities to deliver electric power.  See Item 2
for more information regarding  the transmission and distribution lines.  AEP's
electric utility subsidiaries operate  their  transmission  lines  as  a single
interconnected  and  coordinated system and share the cost and benefits in  the
AEP System Transmission  Pool.   Most  of  the  transmission  and  distribution
services  is  sold, in combination with electric power, to retail customers  of
AEP's utility subsidiaries  in their service territories.  These sales are made
at rates that are established by the public utility commissions of the state in
which they operate.  See RATES.  Some transmission services also are separately
sold to non-affiliated companies.


   AEP SYSTEM TRANSMISSION POOL


   APCo, CSPCo, I&M, KEPCo and  OPCo are parties to the Transmission Agreement,
dated April 1, 1984, as amended (the Transmission Agreement), defining how they
share the costs associated with their  relative  ownership  of  the extra-high-
voltage  transmission  system  (facilities rated 345 kv and above) and  certain
facilities  operated  at  lower  voltages   (138   kv  and  above).   Like  the
Interconnection Agreement, this sharing is based upon  each  company's "member-
load-ratio."  See SALE OF POWER.


   The following table shows the net credits or (charges) allocated  among  the
parties to the Transmission Agreement during the years ended December 31, 1993,
1994 and 1995:

                    1993       1994        1995

                          (in thousands)

APCo             $ (3,200)   $(10,200)   $ (5,400)
CSPCo             (31,200)    (30,100)    (31,100)
I&M                47,400      50,300      46,700
KEPCo               3,800       4,300       3,500
OPCo              (16,800)    (14,300)    (13,700)


   TRANSMISSION SERVICES FOR NON-AFFILIATES


   APCo,  CSPCo,  I&M,  KEPCo,  OPCo  and  other  System companies also provide
transmission services for non-affiliated companies.   The following table shows
the amounts contributed to operating income of the various  companies from such
services during the years ended December 31, 1993, 1994 and 1995:


                     1993       1994      1995

                          (in thousands)

APCo              $ 2,900    $ 4,100    $ 6,000
CSPCo               2,500      3,100      4,200
I&M                 7,700      6,700      4,800
KEPCo                 600        800      1,200
OPCo                9,900     15,700     17,800

   Total System   $23,600    $30,400    $34,000


   The  AEP  System has long-term contracts with non-affiliated  companies  for
transmission of  approximately  690  megawatts  of electric power and contracts
with  non-affiliated companies for transmission during  1996  of  approximately
1,400 megawatts of electric power.


   On April 12, 1993, APCo, CSPCo, I&M, KEPCo and OPCo and two other AEP System
companies  filed  a  transmission  tariff  with  the FERC under which these AEP
System  companies  would  provide  limited  transmission   service  to  certain
companies.  The tariff covered the terms and conditions of the service, as well
as the price which the companies pay for transmission services,  regardless  of
the source of electric power generation.  On September 3, 1993, the FERC issued
an  order accepting the transmission service tariff for filing, with the tariff
becoming  effective  on September 7, 1993, subject to refund.  On May 11, 1994,
the FERC issued an order  on rehearing and indicated that an open access tariff
should offer third parties  access  to  the  transmission system on the same or
comparable basis, and under the same or comparable terms and conditions, as the
transmission provider's access to its system.


   On March 29, 1995, the FERC issued a Notice  of  Proposed Rulemaking ("Mega-
NOPR").  The Mega-NOPR proposes to require each public  utility  that  owns  or
controls  interstate  transmission  facilities  to file open access network and
point-to-point  transmission  tariffs  that offer services  comparable  to  the
utility's own uses of its transmission system.   The Mega-NOPR also proposes to
require utilities to functionally unbundle their services, by requiring them to
use their own tariffs in making off-system and third-party  sales.   As part of
the proposed rule, the FERC issued recommended PRO-FORMA tariffs which  reflect
the   Commission's  preliminary  views  on  the  minimum  non-price  terms  and
conditions for non-discriminatory transmission service.  In connection with the
Mega-NOPR,  the  Commission  offered  certain  waivers  of  its  regulations to
utilities willing to adopt the PRO-FORMA tariffs prior to issuance of the final
rule.   The  Mega-NOPR  also would allow a utility to seek recovery of  certain
prudently-incurred stranded  costs  that  result  from  unbundled  transmission
service.


   On  July 18, 1995, the AEP System companies filed an Offer of Settlement  in
their transmission  tariff  case,  in which the companies proposed to adopt the
FERC's PRO-FORMA transmission tariffs  at  certain stated rates that were lower
than those requested in their initial tariff  filing.   The Offer of Settlement
was  approved  by  the  FERC on February 14, 1996, except for  certain  pricing
issues, which are still pending resolution by FERC.


   AEP has proposed creation  of  an independent system operator to operate the
transmission system in a region of  the  United  States.   See  COMPETITION AND
BUSINESS CHANGE - AEP POSITION ON COMPETITION.

OVEC


   AEP,  CSPCo  and  several unaffiliated utility companies jointly  own  OVEC,
which supplies the power  requirements  of  a  uranium  enrichment  plant  near
Portsmouth,  Ohio  owned by the DOE.  The aggregate equity participation of AEP
and CSPCo in OVEC is 44.2%.  The DOE demand under OVEC's power agreement, which
is subject to change  from time to time, is 1,305,000 kilowatts.  On October 1,
1996, it is scheduled to  increase  to approximately 1,905,000 kilowatts and to
remain at about that level through the  remaining  term  of  the contract.  The
proceeds from the sale of power by OVEC, aggregating $299,000,000  in 1995, are
designed  to  be  sufficient for OVEC to meet its operating expenses and  fixed
costs and to provide  a  return  on  its  equity capital.  APCo, CSPCo, I&M and
OPCo, as sponsoring companies, are entitled  to  receive  from  OVEC,  and  are
obligated  to  pay  for,  the  power not required by DOE in proportion to their
power  participation ratios, which averaged 42.1% in 1995.  The power agreement
with DOE terminates on December  31,  2005, subject to early termination by DOE
on not less than three years notice.  The  power  agreement  among OVEC and the
sponsoring companies expires by its terms on March 12, 2006.

BUCKEYE


   Contractual  arrangements  among  OPCo,  Buckeye  and  other  investor-owned
electric  utility companies in Ohio provide for the transmission and  delivery,
over facilities of OPCo and of other investor-owned utility companies, of power
generated by the two units at the Cardinal Station owned by Buckeye and back-up
power  to  which   Buckeye   is  entitled  from  OPCo  under  such  contractual
arrangements, to facilities owned  by  27  of  the  rural electric cooperatives
which operate in the State of Ohio at 301 delivery points.  Buckeye is entitled
under such arrangements to receive, and is obligated  to pay for, the excess of
its maximum one-hour coincident peak demand plus a 15%  reserve margin over the
1,226,500 kilowatts of capacity of the generating units which Buckeye currently
owns in the Cardinal Station.  Such demand, which occurred on January 18, 1994,
was recorded at 1,146,933 kilowatts.

CERTAIN INDUSTRIAL CUSTOMERS


   Ravenswood Aluminum Corporation and Ormet Corporation operate major aluminum
reduction plants in the Ohio River Valley at Ravenswood,  West Virginia, and in
the vicinity of Hannibal, Ohio, respectively.  OPCo supplies  all  of the power
requirements  of  these  plants  pursuant  to  long-term  contracts  with  such
companies  which,  subject to certain curtailment provisions, terminate in 1997
in  the  case  of Ormet  and  1998  in  the  case  of  Ravenswood.   The  power
requirements  of   such   plants   presently  aggregate  approximately  890,000
kilowatts. OPCo is currently negotiating  with  Ormet  and Ravenswood regarding
the extension of their contracts.  See LEGAL PROCEEDINGS  for  a  discussion of
litigation involving Ormet.

AEGCO


   Since its formation in 1982, AEGCo's business has consisted of the ownership
and  financing  of  its  50%  interest  in the Rockport Plant and, since  1989,
leasing of its 50% interest in Unit 2 of  the  Rockport  Plant.   The operating
revenues  of AEGCo are derived from the sale of capacity and energy  associated
with its interest  in  the  Rockport Plant to I&M, KEPCo and VEPCo, pursuant to
unit power agreements.  Pursuant  to  these  unit  power  agreements,  AEGCo is
entitled  to  recover its full cost of service from the purchasers and will  be
entitled to recover future increases in such costs, including increases in fuel
and capital  costs.   See  UNIT  POWER AGREEMENTS.  Pursuant to a capital funds
agreement, AEP has agreed to provide  cash capital contributions, or in certain
circumstances subordinated loans, to AEGCo,  to  the extent necessary to enable
AEGCo, among other things, to provide its proportionate share of funds required
to permit continuation of the commercial operation of the Rockport Plant and to
perform  all of its obligations, covenants and agreements  under,  among  other
things, all  loan agreements, leases and related documents to which AEGCo is or
becomes a party.  See CAPITAL FUNDS AGREEMENT.


   UNIT POWER AGREEMENTS


   A unit power  agreement  between  AEGCo  and  I&M  (the I&M Power Agreement)
provides  for  the  sale  by  AEGCo  to I&M of all the power  (and  the  energy
associated  therewith)  available to AEGCo  at  the  Rockport  Plant.   I&M  is
obligated, whether or not  power  is  available  from AEGCo, to pay as a demand
charge for the right to receive such power (and as  an  energy  charge  for any
associated energy taken by I&M) such amounts, as when added to amounts received
by AEGCo from any other sources, will be at least sufficient to enable AEGCo to
pay  all  its  operating  and other expenses, including a rate of return on the
common equity of AEGCo as approved  by  FERC,  currently 12.16%.  The I&M Power
Agreement will continue in effect until the date  that  the  last  of the lease
terms of Unit 2 of the Rockport Plant has expired unless extended in  specified
circumstances.


   Pursuant  to an assignment between I&M and KEPCo, and a unit power agreement
between KEPCo  and  AEGCo,  AEGCo  sells KEPCo 30% of the power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KEPCo has agreed to pay to AEGCo in consideration for the right to receive such
power the same amounts which I&M would  have  paid AEGCo under the terms of the
I&M  Power  Agreement for such entitlement.  The  KEPCo  unit  power  agreement
expires on December 31, 1999, unless extended.


   A unit power agreement among AEGCo, I&M, VEPCo, and APCo provides for, among
other things,  the  sale of 70% of the power and energy available to AEGCo from
Unit 1 of the Rockport  Plant  to  VEPCo  by AEGCo from January 1, 1987 through
December 31, 1999.  VEPCo has agreed to pay  to  AEGCo in consideration for the
right to receive such power those amounts which I&M would have paid AEGCo under
the terms of the I&M Power Agreement for such entitlement.   Approximately  34%
of AEGCo's operating revenue in 1995 was derived from its sales to VEPCo.


  CAPITAL FUNDS AGREEMENT


   AEGCo and AEP have entered into a capital funds agreement pursuant to which,
among  other  things,  AEP  has  unconditionally  agreed  to  make cash capital
contributions, or in certain circumstances subordinated loans,  to AEGCo to the
extent  necessary  to enable AEGCo to (i) maintain such an equity component  of
capitalization as required by governmental regulatory authorities, (ii) provide
its proportionate share of the funds required to permit commercial operation of
the Rockport Plant,  (iii)  enable  AEGCo  to  perform  all of its obligations,
covenants and agreements under, among other things, all loan agreements, leases
and related documents to which AEGCo is or becomes a party  (AEGCo Agreements),
and  (iv)  pay  all indebtedness, obligations and liabilities of  AEGCo  (AEGCo
Obligations) under  the  AEGCo Agreements, other than indebtedness, obligations
or liabilities owing to AEP.   The Capital Funds Agreement will terminate after
all AEGCo Obligations have been paid in full.

INDUSTRY PROBLEMS


   The electric utility industry,  including the operating subsidiaries of AEP,
has encountered at various times in the last 15 years significant problems in a
number of areas, including:  delays  in and limitations on the recovery of fuel
costs  from  customers; proposed legislation,  initiative  measures  and  other
actions designed  to  prohibit  construction  and operation of certain types of
power plants under certain conditions and to eliminate  or reduce the extent of
the coverage of fuel adjustment clauses; inadequate rate  increases  and delays
in   obtaining  rate  increases;  jurisdictional  disputes  with  state  public
utilities   commissions  regarding  the  interstate  operations  of  integrated
electric  systems;  requirements  for  additional  expenditures  for  pollution
control facilities;  increased capital and operating costs; construction delays
due, among other factors, to pollution control and environmental considerations
and to material, equipment  and  fuel  shortages;  the  economic effects on net
income  (which when combined with other factors may be immediate  and  adverse)
associated  with  placing  large  generating  units  and  related facilities in
commercial  operation, including the commencement at that time  of  substantial
charges for depreciation,  taxes, maintenance and other operating expenses, and
the  cessation  of AFUDC with  respect  to  such  units;  uncertainties  as  to
conservation efforts  by  customers  and  the  effects  of such efforts on load
growth; depressed economic conditions in certain regions  of the United States;
increasingly  competitive  conditions  in  the  wholesale  and retail  markets;
proposals to deregulate certain portions of the industry and  revise  the rules
and  responsibilities  under  which  new  generating  capacity is supplied; and
substantial increases in construction costs and difficulties  in  financing due
to  high  costs  of  capital,  uncertain capital markets, charter and indenture
limitations restricting conventional  financing,  and  shortages  of  cash  for
construction and other purposes.

SEASONALITY


   Sales of electricity by the AEP System tend to increase and decrease because
of  the  use of electricity by residential and commercial customers for cooling
and heating and relative changes in temperature.

FRANCHISES


   The operating  companies  of  the  AEP  System  hold  franchises  to provide
electric  service  in  various  municipalities  in  their service areas.  These
franchises  have  varying  provisions and expiration dates.   In  general,  the
operating companies consider their franchises to be adequate for the conduct of
their business.

COMPETITION AND BUSINESS CHANGE


   GENERAL


   The public utility subsidiaries  of AEP, like other electric utilities, have
traditionally provided electric generation  and  energy delivery, consisting of
transmission and distribution services, as a single  product  to  their  retail
customers.   FERC  has  proposed  that  utilities  be  required, and the public
utility  subsidiaries  of  AEP  have  agreed,  to  sell  transmission  services
separately from their other services.  Proposals are being made that would also
require  electric  utilities  to sell distribution services separately.   These
proposals generally allow competition  in  the  generation and sale of electric
power, but not in its transmission and distribution.


   Competition  in  the  generation  and sale of electric  power  will  require
resolution of complex issues, including  who will pay for the unused generating
plant of, and other stranded costs incurred  by,  the  utility  when a customer
stops  buying  power  from the utility; will all customers have access  to  the
benefits of competition; how will the rules of competition be established; what
will happen to conservation and other regulatory-imposed programs; how will the
reliability of the transmission  system  be ensured; and how will the utility's
obligation to serve be changed.  As a result,  it  is  not  clear  how  or when
competition  in  generation  and  sale  of  electric  power will be instituted.
However, if competition in generation and sale of electric power is instituted,
the  public  utility  subsidiaries of AEP believe that they  have  a  favorable
competitive position because  of their relatively low costs.  If stranded costs
are not recovered from customers,  however,  the public utility subsidiaries of
AEP,  like  all  electric utilities, will be required  by  existing  accounting
standards to recognize stranded investment losses.


   WHOLESALE


   The  public  utility   subsidiaries  of  AEP,  like  the  electric  industry
generally, face increasing  competition  to sell available power on a wholesale
basis, primarily to other public utilities  and  also  to power marketers.  The
Energy  Policy  Act  of  1992  was  designed,  among  other things,  to  foster
competition  in  the  wholesale  market  (a)  through  amendments   to   PUHCA,
facilitating  the  ownership  and operation of generating facilities by "exempt
wholesale generators" (which may include independent power producers as well as
affiliates of electric utilities)  and  (b)  through  amendments to the Federal
Power  Act, authorizing the FERC under certain conditions  to  order  utilities
which own  transmission  facilities  to provide wholesale transmission services
for  other utilities and entities generating  electric  power.   The  principal
factors  in  competing  for  such  sales  are  price  (including  fuel  costs),
availability  of  capacity  and  reliability  of  service.   The public utility
subsidiaries of AEP believe that they maintain a favorable competitive position
on the basis of all of these factors.  However, because of the  availability of
capacity  of  other utilities and the lower fuel prices in recent years,  price
competition  has  been,  and  is  expected  for  the  next  few  years  to  be,
particularly important.


   The Mega-NOPR  proposes  that utilities be required to functionally unbundle
their transmission services,  by  requiring  them  to  use their own tariffs in
making off-system and third-party sales.  See TRANSMISSION SERVICES.  The Mega-
NOPR also would allow a utility to seek recovery of certain  prudently-incurred
stranded  costs  that result from unbundled transmission service.   The  public
utility subsidiaries  of  AEP  are  preparing  to  functionally  separate their
wholesale  power  sales from their transmission functions, as proposed  in  the
Mega-NOPR and required by their transmission tariffs.


   RETAIL


   The public utility subsidiaries of AEP generally have the exclusive right to
sell electric power  at  retail  within  their service areas.  However, they do
compete with self-generation and with distributors  of  other  energy  sources,
such  as  natural  gas,  fuel  oil  and  coal, within their service areas.  The
primary factors in such competition are price,  reliability  of service and the
capability of customers to utilize sources of energy other than electric power.
With respect to self-generation, the public utility subsidiaries of AEP believe
that  they  maintain a favorable competitive position on the basis  of  all  of
these factors.   With  respect  to  alternative  sources  of energy, the public
utility subsidiaries of AEP believe that the reliability of  their  service and
the limited ability of customers to substitute other cost-effective sources for
electric  power  place  them  in  a favorable competitive position, even though
their prices may be higher than the costs of some other sources of energy.


   Significant changes in the global  economy  in  recent  years  have  led  to
increased  price  competition  for  industrial  companies in the United States,
including  those  served  by  the AEP System.  Such industrial  companies  have
requested price reductions from  their  suppliers, including their suppliers of
electric power.  In addition, industrial  companies  which  are  downsizing  or
reorganizing  often  close  a facility based upon its costs, which may include,
among  other  things,  the  cost   of   electric  power.   The  public  utility
subsidiaries of AEP cooperate with such customers  to meet their business needs
through,  for  example, various off-peak or interruptible  supply  options  and
believe that, as  low  cost  suppliers  of  electric power, they should be less
likely  to be materially adversely affected by  this  competition  and  may  be
benefitted by attracting new industrial customers to their service territories.


   The legislatures  and/or  the  regulatory  commissions in several states are
considering  "retail  customer  choice"  which, in  general  terms,  means  the
transmission by an electric utility of electric power generated by an entity of
the customer's choice over its transmission and distribution system to a retail
customer  in  such  utility's service territory.   A  requirement  to  transmit
directly  to retail customers  would  have  the  result  of  permitting  retail
customers to  purchase  electric  power, at the election of such customers, not
only from the electric utility in whose  service area they are located but from
another electric utility, an independent power  producer  or  an  intermediary,
such  as  a  power  marketer.   Although  AEP's  power  generation  would  have
competitors  under  some  of these proposals, its transmission and distribution
would not.  If competition  develops  in  retail  power  generation, the public
utility  subsidiaries  of  AEP  believe that they have a favorable  competitive
position because of their relatively low costs.


   MICHIGAN:  On June 19, 1995, the  MPSC  approved  an  experimental five-year
retail wheeling program and ordered Consumers Power Company  and Detroit Edison
Company, unaffiliated utilities, to make retail delivery services  available to
a  group  of  industrial  customers,  in  the  amount  of  60  megawatts and 90
megawatts, respectively.  The experiment will commence when each  utility needs
new capacity.  The experiment seeks, as its goal, to determine whether a retail
wheeling  program  best  serves  the  public interest in a manner that promotes
retail competition in a non-discriminatory fashion.  During the experiment, the
MPSC will collect information regarding the effects of retail wheeling.


   In  January  1996,  the Governor of Michigan  endorsed  a  proposal  of  the
Michigan Jobs Commission  to promote competition and customer choice in energy.
Under the proposal, by January  1997, industrial and commercial customers would
be permitted to choose suppliers  for  new electrical load and tariffs would be
unbundled.   By  January 1998, an independent  wholesale  power  pool  with  an
independent operator would be formed.  By 2001, power generation for industrial
and  commercial  would   not  be  subject  to  rate  regulation  and  franchise
territories would be eliminated.


   OHIO:  On April 15, 1994,  the  Ohio Energy Strategy Task Force released its
final report.  The report contained seven broad implementation strategies along
with 53 specific initiatives to be undertaken  by  government  and  the private
sector.   One strategy recommended continuing to encourage competition  in  the
electric utility industry in a manner which maximizes benefits and efficiencies
for all customers.   An  initiative under this strategy recommends facilitating
informal  roundtable  discussions  on  issues  concerning  competition  in  the
electric utility industry  and promoting increased competitive options for Ohio
businesses  that  do  not  unduly   harm   the  interests  of  utility  company
shareholders or ratepayers.  The PUCO has begun such discussions.  As a result,
on February 15, 1996, the PUCO adopted guidelines  for  interruptible  electric
service, including a buy-through provision that will enable customers to  avoid
being  interrupted  during  utility capacity deficiencies by having the utility
purchase off-system replacement power for the customer.


   In March 1996, H.B. 653 was introduced in the Ohio House of Representatives.
The bill proposes that all customers  be  permitted to select their electricity
suppliers effective January 1, 1998.  The bill  eliminates  price regulation of
electricity generation functions in favor of market based prices.  Service area
rights  for  Ohio's  electricity  suppliers  would be confined to  distribution
service.  Transmission and distribution services would continue to be regulated
at the federal and state levels, respectively.   The  bill would require Ohio's
electric utilities to functionally unbundle their generation,  transmission and
distribution  services.   Electric  utilities  would  be  permitted to  recover
transition costs provided that such recovery does not cause  prices  to  exceed
those in effect on the effective date of the legislation.


   VIRGINIA:   In  September 1995, the Virginia SCC instituted a proceeding  to
review and consider  policy regarding restructuring and the role of competition
in the electric utility  industry  in  Virginia.  The Virginia SCC has directed
its staff to conduct an investigation of current issues in the electric utility
industry and to file a report of its observation  and recommendations on issues
identified in the Virginia SCC order.  In addition,  the  Virginia  legislature
has  adopted a resolution establishing a subcommittee to study, in consultation
with the  Virginia  SCC,  restructuring  and  potential changes in the electric
utility industry in Virginia and determine the need for legislative changes.


   AEP POSITION ON COMPETITION


   In  October 1995, AEP announced that it favored  freedom  for  customers  to
purchase  electric  power from anyone that they choose.  Generation and sale of
electric  power  would  be  in  the  competitive  marketplace.   To  facilitate
reliable, safe and  efficient  service,  AEP  supports  creation of independent
system operators to operate the transmission system in a  region  of the United
States.   In  addition, AEP supports the evolution of regional power  exchanges
which would establish  a competitve marketplace for the sale of electric power.
Transmission and distribution would remain monopolies and subject to regulation
with  respect to terms and  price.   Regulators  would  be  able  to  establish
distribution  service charges which would provide, as appropriate, for recovery
of stranded costs and regulatory assets.  Implementation of this proposal would
require legislative changes and regulatory approvals.


   POSSIBLE STRATEGIC RESPONSES


   In response  to the competitive forces and regulatory changes being faced by
AEP and its public  utility  subsidiaries,  as discussed under this heading and
under REGULATION, AEP and its public utility  subsidiaries  have  from  time to
time  considered,  and  expect  to  continue  to  consider,  various strategies
designed to enhance their competitive position and to increase their ability to
adapt  to  and anticipate changes in their utility business.  These  strategies
may include business combinations with other companies, internal restructurings
involving the  complete or partial separation of their generation, transmission
and distribution  businesses,  acquisitions of related or unrelated businesses,
and  additions to or dispositions  of  portions  of  their  franchised  service
territories.   AEP and its public utility subsidiaries may from time to time be
engaged in preliminary  discussions,  either  internally or with third parties,
regarding  one or more of these potential strategies.   No  assurances  can  be
given as to  whether  any potential transaction of the type described above may
actually occur, or as to  its  ultimate  effect  on  the financial condition or
competitive position of AEP and its public utility subsidiaries.


NEW BUSINESS DEVELOPMENT


   AEP  continues  to consider new business opportunities,  particularly  those
which allow use of its  expertise.   These  endeavors  began  in  1982  and are
conducted  through  AEP  Energy  Services, Inc. (AEPES) and AEP Resources, Inc.
(Resources).


   Resources' primary business is  development  of,  and  investment in, exempt
wholesale  generators,  foreign  utility  companies,  qualifying   cogeneration
facilities  and  other  power  projects.  Resources currently does not have  an
interest  in  any power projects.   Resources,  however,  has  entered  into  a
strategic alliance  with  Cogentrix  Energy,  Inc. and Zurn Industries, Inc. to
develop, own and operate industrial power projects  in  the  United  States and
Canada.   In addition, Resources is investigating opportunities to develop  and
invest in new, and invest in existing, generation projects in China, Australia,
Mexico and India.


   In 1994,  AEP  Resources  International,  Limited  (AEPRI),  a  wholly owned
subsidiary  of  Resources,  signed an agreement of intent with Northeast  China
Electric Power Group Corp. (NEPG)  to  design  two  1,300-megawatt,  coal-fired
electric   generating   units  in  Suizhong,  Liaoning  Province,  China.   The
feasibility study for this project has been approved by the Chinese Ministry of
Electric Power and is awaiting  approval  by  the  State  Planning  Commission.
AEPRI  is  also involved in the advanced stages of negotiations to establish  a
joint venture  with  two  Chinese partners to develop and own two 125-megawatt,
coal-fired units in Henan Province, China.  


   AEPES  offers  engineering,   construction,  project  management  and  other
consulting  services  for  projects  involving  transmission,  distribution  or
generation of electric power both domestically and internationally.


   AEP  has  received approval from the  SEC  under  PUHCA  to  finance  up  to
$300,000,000,  and  has  requested  approval  to  finance  up  to  50%  of  its
consolidated  retained earnings (approximately $700,000,000), for investment in
exempt wholesale  generators  and  foreign  utility  companies.   AEP  also has
requested  authority  from the SEC under PUHCA to invest up to $100,000,000  in
subsidiaries engaged in the business of marketing energy commodities, including
electricity and gas.


   These continuing efforts to invest in and develop new business opportunities
offer the potential of earning returns which may exceed those of rate-regulated
operations.  However, they  also  involve a higher degree of risk which must be
carefully considered and assessed.   AEP  may  make  substantial investments in
these and other new businesses.

CONSTRUCTION PROGRAM


   NEW GENERATION


   The AEP System companies are engaged in a continuing  construction  program,
involving  assessment  of needs, selection of sites, design and acquisition  of
equipment, and installation  of  the generating, transmission, distribution and
other  facilities  necessary  to  provide   for  generation,  transmission  and
distribution of electric power.  At the present  time,  there  are  no specific
commitments for additions of new generating stations on the AEP System.   Size,
technology,   type,   ownership  (among  AEP  operating  companies),  means  of
acquisition and precise  timing  of future capacity additions on the AEP System
have  not yet been determined.  However,  the  resource  plan  filed  by  AEP's
electric  utility subsidiaries with various state commissions indicates no need
for new generation until sometime after the year 2000.  Initial future capacity
additions  will  most  likely  be  short  lead  time,  simple-cycle,  gas-fired
combustion turbines.  The current resource plan indicates no need for new coal-
fired baseload  generation until sometime after the year 2010.  The size of any
new coal-fired generation  will  most  likely be significantly smaller than the
1,300-megawatt units last added to the AEP  System,  to  better match projected
load growth.


   Proposals have been made, some of which have been adopted,  that require the
public  utility  subsidiaries  of  AEP to file with state commissions  resource
plans, indicating their plans to satisfy  expected demand for electric power in
their service territory.  When the AEP System  needs  new  generation,  some of
these proposals also require the public utility subsidiaries of AEP which  wish
to  provide  the  new  generation  to compete with exempt wholesale generators,
independent  power  producers  and  other  utilities.   Although  the  specific
guidelines for such competition have  not  yet been developed and may vary from
jurisdiction to jurisdiction (see the discussion  below),  significant  factors
will include price and reliability.


   For  some  years,  the  AEP  System  has  put  in place a series of customer
programs for encouraging electric conservation and  load management (CLM).  The
CLM programs also are referred to in the electric utility  industry as "demand-
side management" programs (DSM) since they affect the demand for electric power
as opposed to its supply.  The AEP System utilizes integrated resource planning
and  has in place a detailed analysis procedure in which effective  demand-side
and supply-side  options  are  both  considered in order to determine the least
cost approach to provide reliable electric  service  for  its customers, taking
into account environmental and other considerations.


   INDIANA:   In  May  1995,  the  IURC  adopted rules for integrated  resource
planning  guidelines,  including  consideration   of   resource   bidding   and
independent  power  producers,  and  for demand-side management.  I&M filed its
first integrated resource plan in November 1995.


   MICHIGAN:  The MPSC has adopted guidelines  governing the acquisition of new
capacity by large Michigan electric utilities.   The guidelines do not apply to
I&M.


   OHIO:  On December 17, 1992, the PUCO issued an  order  proposing  rules for
competitive bidding for new generating capacity, including transmission  access
for   winning  bidders.   The  proposed  rules  would  establish  a  rebuttable
presumption  of  prudence  where  new  generating  capacity is acquired through
competitive bidding and provide other incentives to  use  competitive  bidding.
The  proposed  rules  also  contain  procedures  to  ensure  that bidders for a
utility's new capacity will have open access to certain transmission facilities
and  prohibit  the  utility  acquiring  new  capacity  from  withholding  SO{2}
Allowances  from  potential  bidders.   CSPCo  and OPCo filed comments  on  the
proposed rules generally supporting promulgation of rules governing competitive
bidding but stating that the rules should not address  access  to  transmission
facilities  or  SO{2}  Allowances,  because existing federal laws address  such
concerns.


   VIRGINIA:  On October 24, 1994, the  Virginia  SCC  began  a  proceeding  to
consider  whether  to  adopt standards related to integrated resource planning,
conservation, demand-side  management and energy efficiency in power generation
and supply for jurisdictional  electric  utilities.  On September 27, 1995, the
Virginia SCC declined to adopt the proposed standards, but reaffirmed its goals
for integrated resource planning, investment in cost-effective conservation and
demand management programs.  Virginia electric  utilities  are  to  continue to
file  biennial  twenty-year resource plans.  The Virginia SCC also has  adopted
minimum requirements  for  any  electric  utility  that  elects  to acquire new
generation through a bidding program.  An electric utility is not  required  to
use the bidding process and may participate in the bidding process.


   WEST  VIRGINIA:   On  October 8, 1993, the West Virginia PSC issued an order
proposing  rules  that  generally   require   electric   utilities  to  procure
competitively all new sources of generation.  APCo and Wheeling  Power  Company
filed  comments  stating  that the rules should not require competitive bidding
and should permit the utility to participate in the bidding process.


   PROPOSED TRANSMISSION FACILITIES


   APCO:   On March 23, 1990,  APCo  and  VEPCo  announced  plans,  subject  to
regulatory  approval,   for  major  new  transmission  facilities.   APCo  will
construct approximately 115  miles  of  765,000-volt  line  from APCo's Wyoming
station  in southern West Virginia to APCo's Cloverdale station  near  Roanoke,
Virginia.   VEPCo  will  construct approximately 102 miles of 500,000-volt line
from  APCo's  Joshua Falls station  east  of  Lynchburg,  Virginia  to  VEPCo's
Ladysmith station  north  of  Richmond,  Virginia.   The  construction  of  the
transmission  lines  and  related  station  improvements  will  provide  needed
reinforcement  for  APCo's  internal  load,  reinforce  the ability to exchange
electric power between the two companies and relieve present constraints on the
transmission of electric power from potential independent  power  producers  in
the APCo service area to VEPCo.  APCo's cost is estimated at $245,000,000 while
VEPCo's  cost  is  estimated  at  $164,000,000.   Completion  of the project is
presently scheduled for 2000 but the actual service date will be dependent upon
the time necessary to meet various regulatory requirements.


   Hearings before the Virginia SCC were concluded in September 1993.  A report
was issued by the hearing examiner in December 1993 which recommended  that the
Virginia  SCC grant APCo approval to construct the proposed 765,000-volt  line.
In an interim  order  issued  on December 13, 1995, the Virginia SCC found that
major additional transmission capacity  was  needed to serve APCo's native load
customers.   The  Virginia  SCC  further  asked that  APCo  provide  additional
information on possible routing modifications and utilization of the additional
transmission capacity prior to a final ruling.


   APCo refiled with the West Virginia PSC in February 1993 its application for
certification.  An application filed in June 1992 was withdrawn at the request
of the West Virginia PSC to permit additional time for review by the West
Virginia PSC.  The West Virginia PSC rejected APCo's application for
certification in May 1993, directing APCo to supplement its line siting
information.  APCo intends to refile its application with the West Virginia 
PSC.  Hearings are expected to be held in late 1996 or early 1997, with a 
decision expected in late 1997 or early 1998.


   The Jefferson National  Forest  (JNF)  is  directing  the  preparation of an
Environmental  Impact  Statement  (EIS)  which  will be required prior  to  the
granting  of  special  use  permits for crossing Federal  lands.   The  present
schedule of the JNF calls for  completion of the draft EIS in June 1996 and the
final EIS in early 1998.


   APCO AND KEPCO:  APCo and KEPCo  have  announced  an  improvement plan to be
implemented during a four-year period (1996-1999) to reinforce  their  138,000-
volt transmission system.  Included in this plan is a new transmission line  to
link  KEPCo's  Big  Sandy Plant to communities in eastern Kentucky.  APCo's and
KEPCo's estimated project  costs  are $5,115,000 and $84,184,000, respectively.
Work on the project is scheduled to  begin later in 1996, pending approval from
the KPSC.


   CONSTRUCTION EXPENDITURES


   The  following table shows the construction  expenditures  by  AEGCo,  APCo,
CSPCo, I&M,  KEPCo,  OPCo  and the AEP System and their respective consolidated
subsidiaries during 1993, 1994  and  1995  and  their  current estimate of 1996
construction expenditures, in each case including AFUDC  but  excluding nuclear
fuel and other assets acquired under leases.  The construction expenditures for
the  years  1993-1995  were  applied, and it is anticipated that the  estimated
construction expenditures for 1996 will be applied, approximately as follows to
construction of the following classes of assets:

<TABLE>
<CAPTION>
                                                 1993       1994      1995       1996
                                                ACTUAL     ACTUAL    ACTUAL    ESTIMATE
                                                             (in thousands)
<S>                                            <C>        <C>        <C>        <C>
AEGCO
Generating plant and facilities                $  3,100   $  3,900   $  4,000   $  1,900

   TOTAL                                       $  3,100   $  3,900   $  4,000   $  1,900

APCO
Generating plant and facilities                $ 51,200   $ 65,600   $ 42,400   $ 55,700
Transmission lines and facilities                36,700     38,700     35,200     31,300
Distribution lines and facilities                98,200    116,500    121,400    102,900
General plant and other facilities                4,800      9,500     18,600     13,900

   TOTAL                                       $190,900   $230,300   $217,600   $203,800

CSPCO
Generating plant and facilities                $ 33,300   $ 24,800   $ 30,500   $ 20,400
Transmission lines and facilities                10,100      3,600     10,700     10,800
Distribution lines and facilities                40,700     50,800     56,600     50,800
General plant and other facilities                2,200      2,300      1,700     12,500

   TOTAL                                       $ 86,300   $ 81,500   $ 99,500   $ 94,500
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                                1993       1994       1995        1996
                                               ACTUAL     ACTUAL     ACTUAL     ESTIMATE
                                                            (in thousands)
<S>                                            <C>        <C>        <C>        <C>
I&M
Generating plant and facilities                $ 50,200   $ 49,700   $ 46,200   $ 33,600
Transmission lines and facilities                10,100     20,300     22,600     17,600
Distribution lines and facilities                41,300     42,300     41,500     40,900
General plant and other facilities                6,700      2,200      2,700     18,500

   TOTAL                                       $108,300   $114,500   $113,000   $110,600

KEPCO
Generating plant and facilities                $  8,100   $ 22,600   $  6,200   $ 25,400
Transmission lines and facilities                 6,700      6,400      7,900     33,000
Distribution lines and facilities                20,300     23,700     23,900     23,200
General plant and other facilities                    0        500      1,300      3,400

   TOTAL                                       $ 35,100   $ 53,200   $ 39,300   $ 85,000

OPCO
Generating plant and facilities (a)            $112,700   $ 83,800   $ 40,000   $ 36,200
Transmission lines and facilities                28,600     15,300     23,500     22,000
Distribution lines and facilities                46,000     45,200     51,400     52,200
General plant and other facilities               10,500      4,700      2,000     12,700

   TOTAL                                       $197,800   $149,000   $116,900   $123,100

AEP SYSTEM (b)
Generating plant and facilities (a)            $258,600   $250,400   $169,300   $173,200
Transmission lines and facilities                92,800     85,400    102,500    115,400
Distribution lines and facilities               252,300    286,900    302,800    277,000
General plant and other facilities               24,400     19,400     26,600     61,400

   TOTAL                                       $628,100   $642,100   $601,200   $627,000



</TABLE>
(a) Excludes expenditures associated with flue-gas desulfurization system which
    was constructed by a non-affiliate  at  the Gavin Plant and is being leased
    by OPCo.  Actual expenditures for such system  for  1993, 1994 and 1995 and
    the  current estimate for 1996 are $256,673,000, $176,220,000,  $48,804,000
    and $12,915,000,  respectively.  See ENVIRONMENTAL AND OTHER MATTERS - ACID
    RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN.
(b) Includes expenditures of other subsidiaries not shown.


   Reference is made to  the  footnotes  to  the  financial statements entitled
COMMITMENTS AND CONTINGENCIES incorporated by reference  in Item 8, for further
information  with respect to the construction plans of AEP  and  its  operating
subsidiaries for the next three years.


   The System construction program is reviewed continuously and is revised from
time to time in  response  to changes in estimates of customer demand, business
and economic conditions, the  cost  and  availability of capital, environmental
requirements and other factors.  Changes in  construction  schedules and costs,
and in estimates and projections of needs for additional facilities, as well as
variations  from currently anticipated levels of net earnings,  Federal  income
and other taxes, and other factors affecting cash requirements, may increase or
decrease the  estimates  of  capital requirements for the System's construction
program.


   From time to time, as the System  companies  have  encountered  the industry
problems  described above, such companies also have encountered limitations  on
their  ability   to  secure  the  capital  necessary  to  finance  construction
expenditures.


   ENVIRONMENTAL EXPENDITURES:  Expenditures related to compliance with air and
water quality standards,  included  in  the  gross  additions  to  plant of the
System, during 1993, 1994 and 1995 and the current estimate for 1996  are shown
below. Substantial expenditures in addition to the amounts set forth below  may
be  required  by the System in future years in connection with the modification
and addition of  facilities  at  generating  plants  for  environmental quality
controls  in  order to comply with air and water quality standards  which  have
been or may be adopted.


                   1993    1994    1995     1996
                  ACTUAL  ACTUAL  ACTUAL  ESTIMATE
                        (in thousands)

AEGCo           $      0 $     0 $     0 $     0
APCo              16,800  32,000   7,800   8,500
CSPCo             15,800  13,700  10,000   1,300
I&M                    0       0       0     400
KEPCo              1,000   9,500     600     600
OPCo (a)          31,600  22,400   3,100       0

AEP System (a)   $65,200 $77,600 $21,500 $10,800


(a)Excludes expenditures  associated with flue-gas desulfurization system which
   was constructed by a non-affiliate at the Gavin Plant and is being leased by
   OPCo.  Actual expenditures  for  such system for 1993, 1994 and 1995 and the
   current estimate for 1996 are $256,673,000,  $176,220,000,  $48,804,000  and
   $12,915,000,  respectively.  See ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN
   PROGRAM - AEP SYSTEM COMPLIANCE PLAN.
<PAGE>
FINANCING


  It has been the  practice  of AEP's operating subsidiaries to finance current
construction expenditures in excess  of available internally generated funds by
initially issuing unsecured short-term  debt,  principally commercial paper and
bank loans, at times up to levels authorized by  regulatory  agencies, and then
to  reduce the short-term debt with the proceeds of subsequent  sales  by  such
subsidiaries of long-term debt securities and preferred stock, and cash capital
contributions  by  AEP.   It  has been the practice of AEP, in turn, to finance
cash  capital contributions to the  common  stock  equities  of  the  operating
subsidiaries  by  issuing  unsecured  short-term  debt,  principally commercial
paper,  and  then  to sell additional shares of Common Stock  of  AEP  for  the
purpose of retiring  the  short-term  debt  previously  incurred.  In 1995, AEP
issued  1,400,000  shares of Common Stock pursuant to its Dividend Reinvestment
and Stock Purchase Plan.  Although prevailing interest costs of short-term bank
debt and commercial  paper  generally  have been lower than prevailing interest
costs of long-term debt securities, whenever  interest costs of short-term debt
exceed costs of long-term debt, the companies might  be  adversely  affected by
reliance on  the  use of short-term debt to finance their construction and other
apital requirements.


  During  the  period  1993-1995,  external funds from financings  and  capital
contributions by AEP amounted, with  respect to APCo and KEPCo to approximately
31%  and 53%, respectively, of the aggregate  construction  expenditures  shown
above.   During  this same period, the amount of funds used to retire long-term
and short-term debt  and preferred stock of AEGCo, CSPCo, I&M and OPCo exceeded
the amount of funds from financings and capital contributions by AEP.


  The ability of AEP and its operating subsidiaries to issue short-term debt is
limited by regulatory  restrictions  and,  in the case of most of the operating
subsidiaries, by provisions contained in their charters and in certain debt and
other  instruments.   The approximate amounts  of  short-term  debt  which  the
companies estimate that they were permitted to issue under the most restrictive
such restriction, at January  1, 1996, and the respective amounts of short-term
debt outstanding on that date, on a corporate basis, are shown in the following
tabulation:

<TABLE>
<CAPTION>
                                                                            TOTAL AEP
    SHORT-TERM DEBT       AEP   AEGCO  APCO   CSPCO   I&M    KEPCO   OPCO   SYSTEM(a)
                                               (in millions)
<S>                       <C>    <C>   <C>    <C>     <C>    <C>     <C>    <C>
Amount authorized         $150   $80   $228   $175    $175   $150    $223   $1,256

Amount outstanding:
   Notes payable          $ 18   $22   $ --   $ 13    $ 52   $ 16    $ --   $  128
   Commercial paper         32    --    126     21      38     11       9      237

                          $ 50   $22   $126   $ 34    $ 90   $ 27    $  9   $  365



</TABLE>
(a) Includes short-term debt of other subsidiaries not shown.

   Reference is made to the footnotes  to the financial statements incorporated
by reference in Item 8 for further information  with  respect  to unused short-
term bank lines of credit.


   In order to issue additional first mortgage bonds and preferred stock, it is
necessary for APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage
requirements  contained in their respective mortgages and charters.   The  most
restrictive of these provisions in each instance generally requires (1) for the
issuance of first  mortgage  bonds  for  purposes  other  than the refunding of
outstanding  first  mortgage  bonds,  a  minimum, before income  tax,  earnings
coverage of twice the pro forma annual interest charges on first mortgage bonds
and (2) for the issuance of additional preferred stock by APCo, I&M and OPCo, a
minimum, after income tax, gross income coverage  of one and one-half times pro
forma annual interest charges and preferred stock dividends, in each case for a
period of twelve consecutive calendar months within the fifteen calendar months
immediately preceding the proposed new issue.  In computing such coverages, the
companies  include  as a component of earnings revenues  collected  subject  to
refund (where applicable)  and,  to  the  extent  not limited by the instrument
under which the computation is made, AFUDC, including  amounts  positioned  and
classified  as an allowance for borrowed funds used during construction.  These
coverage provisions  have  from  time  to time restricted the ability of one or
more of the above subsidiaries of AEP to issue senior securities.


   The respective mortgage and preferred  stock  coverages of APCo, CSPCo, I&M,
KEPCo  and  OPCo  under  their  respective  mortgage  and  charter  provisions,
calculated on the foregoing basis and in accordance with the respective amounts
then recorded in the accounts of the companies, assuming  the respective short-
term  debt  of  the companies at those dates were to remain outstanding  for  a
twelve-month period  at  the  respective  rates of interest prevailing at those
dates, were at least those stated in the following table:
<PAGE>
                                  DECEMBER 31,
                               1993   1994   1995

APCo
   Mortgage coverage           3.64   3.12   3.47
   Preferred stock coverage    2.04   1.65   1.78

CSPCo
   Mortgage coverage           2.91   3.64   3.90

I&M
   Mortgage coverage           5.49   6.23   6.25
   Preferred stock coverage    2.48   2.74   2.63

KEPCo
   Mortgage coverage           2.19   2.60   2.86

OPCo
   Mortgage coverage           5.24   5.04   6.17
   Preferred stock coverage    2.88   2.58   3.04

   Although certain other subsidiaries of AEP  either  are  not  subject to any
coverage  restrictions  or  are not subject to restrictions as constraining  as
those to which APCo, CSPCo, I&M,  KEPCo  and OPCo are subject, their ability to
finance substantial portions of their construction  programs  may be subject to
market limitations and other constraints unless other assurances are furnished.


   AEP believes that the ability of its operating subsidiaries  to issue short-
and  long-term debt securities and preferred stock in the amounts  required  to
finance  their  business  may  depend upon the timely approval of rate increase
applications.  If one or more of  the  operating  subsidiaries  are  unable  to
continue  the issuance and sale of securities on an orderly basis, such company
or companies  will  be  required  to  consider the use of alternative financing
arrangements, if available, which may be  more  costly  or  the  curtailment of
construction and other outlays.


   AEP's  subsidiaries  have also utilized, and expect to continue to  utilize,
additional financing arrangements,  such as leasing arrangements, including the
leasing  of  utility  assets,  coal mining  and  transportation  equipment  and
facilities and nuclear fuel.  Pollution control revenue bonds have been used in
the past and may be used in the  future  in connection with the construction of
pollution  control  facilities;  however,  Federal  tax  law  has  limited  the
utilization of this type of financing except  for purposes of certain financing
of  solid  waste disposal facilities and of certain  refunding  of  outstanding
pollution control revenue bonds issued before August 16, 1986.


   Shares of  AEP  Common  Stock may be sold by AEP from time to time at prices
below the then current book  value  per  share and repurchased by AEP at prices
above book value.  Such sales or purchases,  if  any,  would  have  a  dilutive
effect  on  the  book value of then outstanding shares but are not expected  to
have a material adverse effect on AEP's business including its future financing
plans or capabilities and pending construction projects.

RATES


   GENERAL


   The rates charged  by  the electric utility subsidiaries of AEP are approved
by the FERC or one of the state  utility  commissions  as applicable.  The FERC
regulates wholesale rates and the state commissions regulate  retail rates.  In
recent  years the number of rate increase applications filed by  the  operating
subsidiaries  of  AEP  with their respective state commissions and the FERC has
decreased.  If increases  in  operating,  construction and capital costs exceed
increases  in revenues resulting from previously  granted  rate  increases  and
increased customer  demand,  then  it  may  be appropriate for certain of AEP's
electric utility subsidiaries to file rate increase applications in the future.


   Generally  the rates of AEP's operating subsidiaries  are  determined  based
upon the cost of providing service including a reasonable return on investment.
Certain states  served  by  the  AEP  System  allow  alternative  forms of rate
regulation in addition to the traditional cost-of-service approach.   In  April
1995,  Indiana enacted into law legislation providing that the IURC may approve
alternative  regulatory  plans which could include setting customer rates based
on market or average prices, price caps, index-based prices and prices based on
performance  and  efficiency.    In  March  1996,  Virginia  enacted  into  law
legislation which provides that the Virginia SCC may approve (i) special rates,
contracts or incentives to individual  customers  or  classes  of customers and
(ii) alternative forms of regulation including, but not limited  to, the use of
price  regulation,  ranges  of  authorized returns, categories of services  and
price indexing.

   All of the seven states served  by  the  AEP  System,  as  well as the FERC,
either  permit  the  incorporation  of  fuel  adjustment  clauses in a  utility
company's  rates and tariffs, which are designed to permit upward  or  downward
adjustments  in  revenues to reflect increases or decreases in fuel costs above
or below the designated  base  cost of fuel set forth in the particular rate or
tariff, or permit the inclusion  of  specified  levels of fuel costs as part of
such rate or tariff.


   AEP  cannot  predict  the  timing  or  probability  of  approvals  regarding
applications for additional rate changes, the outcome of  action  by regulatory
commissions  or  courts with respect to such matters, or the effect thereof  on
the earnings and business of the AEP System.


   APCO


   FERC:  On February  14,  1992,  APCo filed with the FERC applications for an
increase in its wholesale rates to Kingsport  Power  Company and non-affiliated
customers   in   the  amounts  of  approximately  $3,933,000  and   $4,759,000,
respectively.  APCo  began collecting the rate increases, subject to refund, on
September 15, 1992.  In  addition, the Financial Accounting Standards Board has
issued  Statement  of  Financial   Accounting  Standards  No.  106,  EMPLOYERS'
ACCOUNTING FOR POSTRETIREMENT BENEFITS  OTHER  THAN  PENSIONS (SFAS 106), which
requires  employers,  beginning  in 1993, to accrue for the  costs  of  retiree
benefits other than pensions.  These rates include the higher level of SFAS 106
costs.  On November 9, 1993, the administrative  law  judge  issued  an initial
decision  recommending,  among other things, the higher level of postretirement
benefits  other  than  pensions   under   SFAS  106.   FERC  action  on  APCo's
applications is pending.


   VIRGINIA:  On June 27, 1994, the Virginia  SCC issued a final order granting
APCo  an increase in annual revenues of $17,900,000.   APCo  had  requested  to
increase its Virginia retail rates by $31,400,000 annually and, on May 4, 1993,
implemented  the  rates,  subject  to  refund, based on an interim order.  As a
result of the final order, APCo made a revenue refund including interest to its
Virginia customers in August 1994 of $15,800,000.


   As a result of certain significant fuel  cost  reductions,  on  November 15,
1994,  APCo implemented a net decrease in rates charged to its Virginia  retail
customers  of  $13,200,000, subject to final approval by the Virginia SCC.  The
net decrease consisted  of  a $28,900,000 decrease in the fuel component of its
rates  offset, in part, by an  increase  of  $15,700,000  in  base  rates.   On
December  19,  1994, the Virginia SCC issued an order approving the decrease in
the fuel factor  component of rates.  APCo proposes in the base rate proceeding
to amortize Virginia  deferred  storm damage expenses of $23,900,000 related to
two major ice storms in February  and  March  1994  over  a  three-year period,
consistent  with  the  amortization of previous storm damage expense  deferrals
approved in a 1992 rate  case.   The  ultimate  recovery of the entire deferred
storm  damage  costs  is subject to Virginia SCC approval.   If  not  approved,
results of operations could  be adversely affected.  The Virginia SCC Staff has
recommended that approximately  $12,000,000  of the $23,900,000 in storm damage
expenses  be  treated as if they have previously  been  recovered  in  earnings
(based on the results  of  the  Staff's  earnings  test)  and  the remainder be
deferred  for  future  recovery over a five-year period.  A hearing  examiner's
report is pending.


   CSPCO


   ZIMMER PLANT:  The Zimmer  Plant  was  placed  in  commercial operation as a
1,300-megawatt coal-fired plant on March 30, 1991.  CSPCo  owns  25.4%  of  the
Zimmer  Plant  with  the  remainder  owned  by two unaffiliated companies, CG&E
(46.5%) and DP&L (28.1%).


   ZIMMER  PLANT  -  RATE RECOVERY:  In May 1992,  the  PUCO  issued  an  order
providing for a phased-in rate increase of $123,000,000 for the Zimmer Plant to
be  implemented  in  three   steps   over  a  two-year  period  and  disallowed
$165,000,000  of Zimmer Plant investment.   CSPCo  appealed  the  PUCO  ordered
Zimmer disallowance  and  phase-in plan to the Ohio Supreme Court.  In November
1993, the Supreme Court issued  a  decision  on  CSPCo's  appeal  affirming the
disallowance  and  finding  that  the PUCO did not have statutory authority  to
order phased-in rates.  The court instructed  the  PUCO to fix rates to provide
gross annual revenue in accordance with the law and  to  provide a mechanism to
recover the revenues deferred under the phase-in order.


   As a result of the ruling, 1993 net income was reduced by $144,500,000 after
tax to reflect the disallowance and in January 1994, the PUCO  approved a 7.11%
or  $57,167,000  rate  increase  effective  February 1, 1994.  The increase  is
comprised of a 3.72% base rate increase and a  temporary 3.39% surcharge, which
will be in effect until the phase-in plan deferrals  are  recovered,  currently
estimated to be mid-1997.  In 1995, $28,500,000 of net phase-in deferrals  were
collected through the surcharge which reduced the deferrals from $75,400,000 at
December  31,  1994  to  $46,900,000  at  December 31, 1995.  In 1993 and 1992,
$47,900,000 and $46,000,000, respectively,  were  deferred  under  the phase-in
plan.   The  recovery  of  amounts  deferred  under  the phase-in plan and  the
increase in rates to the full rate level did not affect net income.


   From the in-service date of March 1991 until rates  went  into effect in May
1992,  deferred  carrying  charges of $43,000,000 were recorded on  the  Zimmer
Plant investment.  Recovery  of the deferred carrying charges will be sought in
the next PUCO base rate proceeding in accordance with the PUCO accounting order
that authorized the deferral.


   Reference is made to the caption ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN
PROGRAM - AEP SYSTEM COMPLIANCE PLAN for information regarding AEP's compliance
plan which was approved by the PUCO.


   KEPCO


   In September 1995, KEPCo, the Kentucky Attorney General and other interested
parties filed an application with  the KPSC to implement KEPCo's DSM Three-Year
Experimental Plan which consisted of  DSM  programs for residential, commercial
and industrial sectors.  Under the plan, program  costs,  as  well  as net lost
revenues and incentives, would be recovered by sector under an annual surcharge
tariff.   In  December  1995, the KPSC issued an order approving the three-year
plan for the period ending December 31, 1998.


   OPCO


   An application was filed  by  OPCo  in  July  1994  with  the PUCO seeking a
$152,500,000 annual base retail rate increase to recover, among  other  things,
the  costs  associated  with the Gavin Plant's flue gas desulfurization systems
(scrubbers).   In  February  1995,  OPCo  and  certain  other  parties  to  the
proceeding entered into  a settlement agreement to resolve, among other issues,
the pending base rate case  and  the  current  electric  fuel  component  (EFC)
proceeding.   On  March  23,  1995,  the  PUCO  issued  an  order approving the
settlement agreement, with certain minor exceptions.  Under the  terms  of  the
settlement  agreement,  effective  March  23,  1995,  base  rates  increase  by
$66,000,000  annually  which  includes  recovery  of  the  annual  cost  of the
scrubbers;  the  EFC  rate  is  fixed  at 1.465 cents per kwh from June 1, 1995
through November 30, 1998; OPCo is provided with the opportunity to recover its
Ohio jurisdictional share of the investment  in, and the liabilities and future
shutdown costs of, all affiliated mines as well  as  any  fuel  costs  incurred
above the fixed rate; and OPCo may proceed with its Clean Air Act Amendments of
1990 compliance plan as filed with the PUCO (discussed under ENVIRONMENTAL  AND
OTHER  MATTERS  -  ACID  RAIN  PROGRAM  -  AEP  SYSTEM  COMPLIANCE  PLAN).  The
settlement  agreement  allows  OPCo  to  continue to operate its Muskingum  and
Windsor mines.


   Based on a stipulation agreement approved  by  the  PUCO  in  November 1992,
beginning  December  1,  1994,  the  cost of coal burned at the Gavin Plant  is
subject  to a 15-year predetermined price  of  $1.575  per  million  Btus  with
quarterly  escalation  adjustments.   As  discussed  above,  the  PUCO-approved
settlement agreement fixes the EFC factor at 1.465 cents per kwh for the period
June 1995 through November 1998.  After November 2009, the price that  OPCo can
recover for coal from its affiliated Meigs mine which supplies the Gavin  Plant
will  be  limited  to  the lower of cost or the then-current market price.  The
predetermined Gavin Plant  price  agreement,  in  conjunction  with  the above-
referenced  settlement  agreement,  provide OPCo with an opportunity to recover
any operating losses incurred under the  predetermined  or fixed price, as well
as  its investment in, and liabilities and closing costs associated  with,  its
affiliated  mining  operations  attributable  to  its Ohio jurisdiction, to the
extent  the  actual  cost  of  coal  burned at the Gavin  Plant  is  below  the
predetermined price.


   Based on the estimated future cost of coal burned at Gavin Plant, management
believes  that  the Ohio jurisdictional  portion  of  the  investment  in,  and
liabilities and closing  costs  of,  the  affiliated  mining operations will be
recovered under the terms of the predetermined price agreement.


   In  November  1992,  the  municipal  wholesale customers  of  OPCo  filed  a
complaint with the SEC requesting an investigation  of the sale of the Martinka
mining  operation  to  an  unaffiliated company and an investigation  into  the
pricing of OPCo's affiliated  coal  purchases  back  to 1986.  OPCo has filed a
response with the SEC seeking to dismiss this complaint.

FUEL SUPPLY


   The following table shows the sources of power generated by the AEP System:

                   1991   1992   1993   1994   1995

Coal                86%    93%    86%    91%    88%
Nuclear             13%     6%    13%     8%    11%
Hydroelectric 
 and other           1%     1%     1%     1%     1%


   Variations  in  the  generation  of nuclear power are primarily  related  to
refueling outages and, in 1992, a forced outage at Cook Plant Unit 2.  See COOK
NUCLEAR PLANT.


   COAL


   The Clean Air Act Amendments of 1990  provide  for  the  issuance  of annual
allowance  allocations  covering  sulfur  dioxide  emissions  at  levels  below
historic  emission  levels  for  many  coal-fired  generating  units of the AEP
System.   Phase  I of this program began in 1995 and Phase II begins  in  2000,
with both phases requiring  significant changes in coal supplies and suppliers.
The full extent of such changes,  particularly  in regard to Phase II, however,
has  not  been determined.  See ENVIRONMENTAL AND OTHER  MATTERS  -  ACID  RAIN
PROGRAM - AEP SYSTEM COMPLIANCE PLAN for the current compliance plan.


   In order  to  meet emission standards for existing and new emission sources,
the AEP System companies  will,  in any event, have to obtain coal supplies, in
addition  to  coal  reserves  now  owned   by  System  companies,  through  the
acquisition  of additional coal reserves and/or  by  entering  into  additional
supply agreements,  either  on  a  long-term  or spot basis, at prices and upon
terms which cannot now be predicted.


   No representation is made that any of the coal rights owned or controlled by
the System will, in future years, produce for the  System  any major portion of
the  overall  coal  supply needed for consumption at the coal-fired  generating
units of the System.   Although  AEP  believes  that in the long run it will be
able to secure coal of adequate quality and in adequate  quantities  to  enable
existing  and  new  units  to comply with emission standards applicable to such
sources, no assurance can be  given that coal of such quality and quantity will
in fact be available.  No assurance  can  be  given  either  that  statutes  or
regulations  limiting  emissions  from  existing  and  new  sources will not be
further revised in future years to specify lower sulfur contents  than  now  in
effect or other restrictions.  See ENVIRONMENTAL AND OTHER MATTERS herein.


   The  FERC  has  adopted  regulations  relating,  among  other things, to the
circumstances under which, in the event of fuel emergencies  or  shortages,  it
might order electric utilities to generate and transmit electric power to other
regions  or  systems experiencing fuel shortages, and to rate-making principles
by which such  electric  utilities  would  be  compensated.   In  addition, the
Federal Government is authorized, under prescribed conditions, to allocate coal
and to require the transportation thereof, for the use of power plants or major
fuel-burning installations.


   System companies have developed programs to conserve coal supplies at System
plants which involve, on a progressive basis, limitations on sales of power and
energy to neighboring utilities, appeals to customers for voluntary limitations
of  electric  usage  to  essential  needs,  curtailment  of  sales  to  certain
industrial customers, voltage reductions and, finally, mandatory reductions  in
cases  where  current  coal  supplies fall below minimum levels.  Such programs
have been filed and reviewed with  officials of Federal and state agencies and,
in some cases, the state regulatory  agency  has prescribed actions to be taken
under specified circumstances by System companies,  subject to the jurisdiction
of such agencies.


   The mining of coal reserves is subject to Federal  requirements with respect
to the development and operation  of  coal  mines, and to state and Federal
regulations  relating  to  land reclamation  and  environmental  protection,  
including  Federal  strip  mining legislation enacted in August 1977.  
Continual evaluation and study is given to possible closure of  existing coal 
mines and divestiture or acquisition of coal properties in light of  Federal
and  state  environmental  and mining laws and regulations which may affect
the System's need for or ability  to  mine  such coal.


   Western coal purchased  by  System  companies  is  transported  by rail to a
terminal  on  the  Ohio  River  for  transloading  to  barges  for  delivery to
generating  stations  on  the  river.   Subsidiaries of AEP lease approximately
3,535  coal hopper cars to be used in unit  train  movements,  as  well  as  14
towboats,  295  jumbo barges and 185 standard barges.  Subsidiaries of AEP also
own or lease coal transfer facilities at various locations on the river.


   The System generating  companies  procure  coal from coal reserves which are
owned or mined by subsidiaries of AEP, and through  purchases pursuant to long-
term contracts, or on a spot purchase basis, from unaffiliated  producers.  The
following table shows the amount of coal delivered to the AEP System during the
past  five  years,  the proportion of such coal which was obtained either  from
coal-mining subsidiaries, from unaffiliated suppliers under long-term contracts
or through spot or short-term  purchases,  and  the  average delivered price of
spot coal purchased by System companies:
<TABLE>
<CAPTION>

                                            1991   1992   1993   1994   1995
<S>                                        <C>    <C>    <C>    <C>    <C>
Total coal delivered to
   AEP operated plants (thousands of tons) 45,232 44,738 40,561 49,024 46,867
Sources (percentage):
   Subsidiaries                              28%    25%    20%    15%    14%
   Long-term contracts                       62%    65%    66%    65%    75%
   Spot or short-term purchases              10%    10%    14%    20%    11%
Average price per ton of spot-purchased 
   coal                                  $25.40   $23.88 $23.55 $23.00 $25.15

</TABLE>

   The  average cost of coal consumed during the past five  years  by  all  AEP
System companies,  AEGCo,  APCo,  CSPCo,  I&M,  KEPCo  and OPCo is shown in the
following tables:
<TABLE>
<CAPTION>
                                           1991   1992   1993   1994   1995
                                                     Dollars per ton
<S>                                        <C>    <C>    <C>    <C>    <C>
AEP System Companies                       $35.16 $34.31 $33.57 $33.95 $32.52
AEGCo                                       20.65  20.11  17.74  18.59  18.80
APCo                                        41.99  43.00  42.65  39.89  38.86
CSPCo                                       35.18  33.87  33.87  32.80  33.23
I&M                                         25.57  24.23  23.80  22.85  23.25
KEPCo                                       31.38  30.24  27.08  26.83  26.91
OPCo                                        40.18  38.36  38.12  41.10  37.58


                                          CENTS PER MILLION BTU'S

AEP System Companies                        158.88<cent>154.41<cent>150.89<cent>152.41<cent>145.26<cent>
AEGCo                                       123.33 120.90  107.71 112.06 112.87
APCo                                        169.48 173.05  173.32 161.37 156.96
CSPCo                                       152.55 143.94  143.66 140.45 140.79
I&M                                         139.16 135.11  129.39 123.62 125.50
KEPCo                                       132.25 126.92  113.90 113.40 114.77
OPCo                                        171.65 163.89  161.25 173.51 157.62
<PAGE>
   The  coal  supplies  at  AEP  System plants vary from time to time 
plants vary from time to time depending on various factors, including 
customers'  usage  of  electric  power, space limitations, the rate of
consumption at particular plants, labor unrest and weather conditions 
which may interrupt deliveries.  At December 31, 1995, the System's coal
inventory was approximately 55 days of normal System usage.  This estimate 
assumes that the total supply would be utilized by increasing or decreasing 
generation at particular plants. 

   The following tabulation shows the total consumption during 1995 of the
coal-fired generating units of AEP's principal electric utility subsidiaries,
coal requirements of these units over the remainder of their useful lives
and the average sulfur content of coal delivered in 1995 to these units.
Reference is made to ENVIRONMENTAL AND OTHER MATTERS for information 
concerning current emissions limitations in the AEP System's various
jurisdictions and the effects of the Clean Air Act Amendments.



</TABLE>
<TABLE>
<CAPTION>
                                                      ESTIMATED REQUIRE-        AVERAGE SULFUR CONTENT
                                 TOTAL CONSUMPTION    MENTS FOR REMAINDER         OF DELIVERED COAL
                                    During 1995        of Useful Lives            Pounds of SO{2}
                              (IN THOUSANDS OF TONS)  (IN MILLIONS OF TONS)     BY WEIGHT   PER MILLION BTU'S
<S>                           <C>                       <C>                     <C>         <C>
AEGCo (a)                     5,267                     261                     0.3%        0.7
APCo                          8,988                     446                     0.8%        1.3
CSPCo (b)                     5,367                     234                     2.9%        4.9
I&M (c)                       6,723                     300                     0.5%        1.1
KEPCo                         2,953                      91                     1.2%        2.0
OPCo                         17,910                     650                     2.2%        3.7


</TABLE>
(a) Reflects AEGCo's 50% interest in the Rockport Plant.
(b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and
    Zimmer Plants.
(c) Includes I&M's 50% interest in the Rockport Plant.

   AEGCO:  See FUEL SUPPLY - I&M for a discussion of the coal supply for the
Rockport Plant.


   APCO:  Substantially all of the coal consumed at APCo's generating plants is
obtained from unaffiliated suppliers under long-term contracts and/or on a spot
purchase basis.


   The average sulfur content by weight of the coal received by APCo at its
generating stations approximated 0.8% during 1995, whereas the maximum sulfur
content permitted, for emission standard purposes, for existing plants in the
regions in which APCo's generating stations are located ranged between 0.78%
and 2% by weight depending in some circumstances on the calorific value of the
coal which can be obtained for some generating stations.


   CSPCO:  CSPCo has coal supply agreements with unaffiliated suppliers for the
delivery of approximately 3,400,000 tons per year through 1998.  Some of this
coal is washed to improve its quality and consistency for use principally at
Unit 4 of the Conesville Plant.


   CSPCo has been informed by CG&E and DP&L that, with respect to the CCD Group
units partly owned but not operated by CSPCo, sufficient coal has been
contracted for or is believed to be available for the approximate lives of the
respective units operated by them.  Under the terms of the operating agreements
with respect to CCD Group units, each operating company is contractually
responsible for obtaining the needed fuel.
<PAGE>

   I&M:  I&M has three coal supply agreements with unaffiliated suppliers
pursuant to which the suppliers are delivering low sulfur coal from surface
mines in Wyoming, principally for consumption by the Rockport Plant.  Under
these agreements, the suppliers will sell to I&M, for consumption by I&M at the
Rockport Plant or consignment to other System companies, coal with an average
sulfur content not exceeding 1.2 pounds of sulfur dioxide per million Btu's of
heat input.  One contract with remaining deliveries of 67,750,000 tons expires
on December 31, 2014 and another contract with remaining deliveries of
56,400,000 tons expires on December 31, 2004.  The third contract with
deliveries of 750,000 tons per year expires in late 1996.


   All of the coal consumed at I&M's Tanners Creek Plant is obtained from
unaffiliated suppliers under long-term contracts and/or on a spot purchase
basis.


   KEPCO:  Substantially all of the coal consumed at KEPCo's Big Sandy Plant is
obtained from unaffiliated suppliers under long-term contracts and/or on a spot
purchase basis.  KEPCo has coal supply agreements with unaffiliated suppliers
pursuant to which KEPCo will receive approximately 2,500,000 tons of coal in
1996.  To the extent that KEPCo has additional coal requirements, it may
purchase coal from the spot market and/or suppliers under contract to supply
other System companies.


   OPCO:  The coal consumed at OPCo's generating plants is obtained from both
affiliated and unaffiliated suppliers.  The coal obtained from unaffiliated
suppliers is purchased under long-term contracts and/or on a spot purchase
basis.


   OPCo and certain of its coal-mining subsidiaries own or control coal
reserves in the State of Ohio which contain approximately 212,000,000 tons of
clean recoverable coal, which ranges in sulfur content between 3.4% and 4.5%
sulfur by weight (weighted average, 3.8%), which can be recovered based upon
existing mining plans and projections and employing current mining practices
and techniques.  OPCo and certain of its mining subsidiaries own an additional
113,000,000 tons of clean recoverable coal in Ohio which ranges in sulfur
content between 2.4% and 3.4% sulfur by weight (weighted average 2.7%).
Recovery of this coal would require substantial development.


   OPCo and certain of its coal-mining subsidiaries also own or control coal
reserves in the State of West Virginia which contain approximately 106,000,000
tons of clean recoverable coal ranging in sulfur content between 1.4% and 3.3%
sulfur by weight (weighted average, 2.0%) of which approximately 29,000,000
tons can be recovered based upon existing mining plans and projections and
employing current mining practices and techniques.
<PAGE>

   NUCLEAR


   I&M has made commitments to meet certain of the nuclear fuel requirements of
the Cook Plant.  The nuclear fuel cycle consists of the mining and milling of
uranium ore to uranium concentrates; the conversion of uranium concentrates to
uranium hexafluoride; the enrichment of uranium hexafluoride; the fabrication
of fuel assemblies; the utilization of nuclear fuel in the reactor; and the
reprocessing or other disposition of spent fuel.  Steps currently are being
taken, based upon the planned fuel cycles for the Cook Plant, to review and
evaluate I&M's requirements for the supply of nuclear fuel beyond the existing
contractual commitments shown in the following table.  I&M has made and will
make purchases of uranium in various forms in the spot and short-term market
until it decides that deliveries under mid- or long-term supply contracts are
warranted.  The following table shows the year through which contracts have
been entered into to provide the requirements of the units for the various
segments of the nuclear fuel cycle.

<TABLE>
<CAPTION>
                   URANIUM
                 CONCENTRATES    CONVERSION       ENRICHMENT (1)  FABRICATION    REPROCESSING (2)
<S>              <C>             <C>              <C>             <C>            <C>

Unit 1            --              --                 2000             2000          --
Unit 2            --              --                 2000             2000          --

</TABLE>

1) I&M has a requirements-type contract with DOE.  I&M has partially terminated
   the contract, subject to revocation of the termination, so that it may
   procure enrichment services cost-effectively from the spot market.
2) No reprocessing facility in the United States currently is in operation.
   I&M has contracted for reprocessing services at a facility on which
   construction has been halted.  Lack of reprocessing services has resulted in
   the need to increase on-site storage capacity for spent fuel.


   For purposes of the storage of high-level radioactive waste in the form of
spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel
storage pool to permit normal operations through 2010.


   I&M's costs of nuclear fuel consumed do not assume any residual or salvage
value for residual plutonium and uranium.


   NUCLEAR WASTE AND DECOMMISSIONING


   The Nuclear Waste Policy Act of 1982, as amended, establishes Federal
responsibility for the permanent off-site disposal of spent nuclear fuel and
high-level radioactive waste.  Disposal costs are paid by fees assessed against
owners of nuclear plants and deposited into the Nuclear Waste Fund created by
the Act.  In 1983, I&M entered into a contract with DOE for the disposal of
spent nuclear fuel.  Under terms of the contract, for the disposal of nuclear
fuel consumed after April 6, 1983 by I&M's Cook Plant, I&M is paying to the
fund a fee of one mill per kilowatt-hour, which I&M is currently recovering
from customers.  For the disposal of nuclear fuel consumed prior to April 7,
1983, I&M must pay the U.S. Treasury a fee estimated at approximately
$71,964,000, exclusive of interest of $91,096,000 at December 31, 1995.  The
aggregate amount has been recorded as long-term debt.  Because of the current
uncertainties surrounding DOE's program to provide for permanent disposal of
spent nuclear fuel, I&M has not yet paid any of the pre-April 1983 fee.  At
December 31, 1995, funds collected from customers to pay the pre-April 1983 fee
and accrued interest approximated the long-term debt liability.


   On June 20, 1994, a group of 14 unaffiliated utilities owning and operating
nuclear plants and a group of states each filed a petition for review in the
U.S. Court of Appeals for the District of Columbia Circuit requesting that the
court issue a declaration that the Nuclear Waste Policy Act of 1982 imposes on
DOE an unconditional obligation to begin acceptance of spent nuclear fuel and
high level radioactive waste by January 31, 1998.  DOE has indicated in its
Notice of Inquiry of May 25, 1994 that its preliminary view is that it has no
statutory obligation to begin to accept spent nuclear fuel beginning in 1998 in
the absence of an operational repository.  In April 1995, DOE issued its Final
Interpretation affirming its earlier view.  On May 30, 1995, I&M filed a
petition for review seeking the same relief requested earlier by the group of
utilities.  This action was consolidated with the earlier petition.  I&M also
seeks, if warranted, relief from the financial burden of fees being paid to
DOE.


   Studies completed in 1994 estimate decommissioning and low-level radioactive
waste disposal costs for the Cook Plant to range from $634,000,000 to
$988,000,000 in 1993 nondiscounted dollars.  The wide range is caused by
variables in assumptions, including the estimated length of time spent nuclear
fuel must be stored at the Cook Plant subsequent to ceasing operations, which
depends on future developments in the federal government's spent nuclear fuel
disposal program.  Continued delays in the federal fuel disposal program can
result in increased decommissioning costs.  I&M is recovering decommissioning
costs in its three rate-making jurisdictions based on at least the lower end of
the range in the most recent respective decommissioning study available at the
time of the rate proceeding (the study range utilized in the Indiana rate case,
I&M's primary jurisdiction, was $588,000,000 to $1.102 billion in 1991
dollars).  I&M records decommissioning costs in other operation expense and
records a noncurrent liability equal to the decommissioning cost recovered in
rates which was $30,000,000 in 1995, $26,000,000 in 1994 and $13,000,000 in
1993.  At December 31, 1995, I&M had recognized a decommissioning liability of
$269,000,000.  I&M will continue to reevaluate periodically the cost of
decommissioning and to seek regulatory approval to revise its rates as
necessary.


   Funds recovered through the rate-making process for disposal of spent
nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning
have been segregated and deposited in external funds for the future payment of
such costs.  Trust fund earnings decrease the amount to be recovered from
ratepayers.


   The ultimate cost of retiring I&M's Cook Plant may be materially different
from the estimates contained in the site-specific study and the funding targets
as a result of (a) the type of decommissioning plan selected, (b) the
escalation of various cost elements (including, but not limited to, general
inflation), (c) the further development of regulatory requirements governing
decommissioning, (d) the absence to date of significant experience in
decommissioning such facilities and (e) the technology available at the time of
decommissioning differing significantly from that assumed in these studies.
Accordingly, management is unable to provide assurance that the ultimate cost
of decommissioning the Cook Plant will not be significantly greater than
current projections.


   In February 1996, the Financial Accounting Standards Board (FASB) issued an
exposure draft entitled ACCOUNTING FOR CERTAIN LIABILITIES RELATED TO CLOSURE
OR REMOVAL OF LONG-LIVED ASSETS.  The exposure draft proposes that the present
value of any decommissioning or other closure or removal obligation be recorded
as a liability when the obligation is incurred.  A corresponding asset would be
recorded in the plant investment account and recovered through depreciation
charges over the asset's life.  A proposed transition rule would require that
an entity report a charge to income for the cumulative effect of initially
applying the proposed standard.  Management is studying the proposed standard
and evaluating its potential impact.


   The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the
responsibility for the disposal of low-level waste rests with the individual
states.  Low-level radioactive waste consists largely of ordinary trash and
other items that have come in contact with radioactive materials.  To
facilitate this approach, the LLWPA authorized states to enter into regional
compacts for low-level waste disposal subject to Congressional approval.  The
LLWPA also specified that, beginning in 1986, approved compacts may prohibit
the importation of low-level waste from other regions, thereby providing a
strong incentive for states to enter into compacts.  As 1986 approached it
became apparent that no new disposal facilities would be operational, and
enforcement of the LLWPA would leave no disposal capacity for the majority of
the low-level waste generated in the United States.  Congress, therefore,
passed the Low-Level Waste Policy Amendments Act of 1985.  Michigan, the state
where the Cook Plant is located, was a member of the Midwest Compact, but its
membership was revoked in 1991.  Michigan is responsible for developing a
disposal site for the low-level waste generated in Michigan.


   In 1994, Michigan amended its law regarding disposal sites to provide for
allowing a volunteer to host a facility.  Although progress has been made, the
site selection process is very long and management is unable to predict when a
permanent disposal site for Michigan low-level waste will be available.


   On July 1, 1995, the disposal site in South Carolina reopened to accept
waste from most areas of the U.S., including Michigan.  This is the first
opportunity for the Cook Plant to dispose of waste at that site since November
1990 when South Carolina denied access to its disposal site.  To the extent
necessary, the Cook Plant's low-level radioactive waste is being stored on-
site.  I&M has an on-site radioactive material storage facility at the Cook
Plant for temporary preshipment storage of the plant's low-level radioactive
waste.  The facility can hold as much low-level waste as the Cook Plant is
expected to produce through approximately 2001, and the building could be
expanded to accommodate the storage of such waste through approximately 2017.
Currently, the Cook Plant produces less than 7,000 cubic feet of low-level
waste annually.


   ENERGY POLICY ACT - NUCLEAR FEES


   The Energy Policy Act of 1992 (Energy Act), contains a provision to fund the
decommissioning and decontamination of DOE's existing uranium enrichment
facilities from a combination of sources including assessments against electric
utilities which purchased enrichment services from DOE facilities.  I&M's
remaining estimated liability is $45,703,000, subject to inflation adjustments,
and is payable in annual assessments over the next 11 years.  I&M recorded a
regulatory asset concurrent with the recording of the liability.  The payments
are being recorded and recovered as fuel expense.


   In a case involving an unaffiliated utility, the U.S. Court of Federal
Claims decided in June 1995 that these assessments are unlawful.  On November
13, 1995, the Federal Government appealed this decision to the U.S. Court of
Appeals for the Federal Circuit.  I&M has filed with DOE claims for refunds
under certain of its enrichment services contracts based on this decision.  I&M
also intends to pursue refund claims on other enrichment services contracts
directly to the U.S. Court of Federal Claims.

ENVIRONMENTAL AND OTHER MATTERS


   AEP's subsidiaries are subject to regulation by Federal, state and local
authorities with regard to air and water-quality control and other
environmental matters, and are subject to zoning and other regulation by local
authorities.


   It is expected that costs related to environmental requirements will
eventually be reflected in the rates of AEP's electric utility subsidiaries and
that, in the long term, AEP's electric utility subsidiaries will be able to
provide for such environmental controls as are required.  However, some
customers may curtail or cease operations as a consequence of higher energy
costs.  There can be no assurance that all such costs will be recovered.


   Except as noted herein, AEP's subsidiaries which own or operate generating
facilities generally are in compliance with pollution control laws and
regulations.


   AIR POLLUTION CONTROL


   CLEAN AIR ACT AMENDMENTS OF 1990:  For the AEP System, compliance with the
Clean Air Act Amendments of 1990 (CAAA) is requiring substantial expenditures
which are being recovered through increases in the rates of AEP's operating
subsidiaries.  OPCo is incurring a major portion of such costs.  There can be
no assurance that all such costs will be recovered.  See CONSTRUCTION PROGRAM -
CONSTRUCTION EXPENDITURES.


   The Acid Rain Program provisions of the CAAA create an emission allowance
program pursuant to which utilities are authorized to emit a designated
quantity of sulfur dioxide, measured in tons per year, on a system wide or
aggregate basis.  Emission reductions are required by virtue of the
establishment of annual allowance allocations at a level below historical
emission levels for many utility units.  For units that emitted sulfur dioxide
above a rate of 2.5 pounds per million Btu heat input in 1985, the CAAA
establish sulfur dioxide allowance limitations (caps or ceilings on emissions)
premised upon sulfur dioxide emissions at a rate of 2.5 pounds per million Btu
heat input at 1985 utilization levels as of the Phase I deadline of January 1,
1995.  The following AEP System units are Phase I-affected units:  I&M's Breed
Plant and Tanners Creek Unit 4; CSPCo's Beckjord Unit 6, Conesville Units 1-4,
Picway Unit 5 and Stuart Units 1-4; and OPCo's Gavin Units 1-2, Muskingum River
Units 1-5, Cardinal Unit 1, Mitchell Units 1-2 and Kammer Units 1-3.  Phase I
permits have been issued for all Phase I-affected units in the AEP System.


   All fossil fuel-fired steam generating units with capacity greater than 25
megawatts are affected in Phase II of the acid rain control program.  All Phase
II-affected units are allocated allowances with which compliance must be
accomplished beginning January 1, 2000.  The basis for Phase II allowance
allocation depends on 1985 sulfur dioxide emission rates - if a unit emitted
sulfur dioxide in 1985 at a rate in excess of 1.2 pounds per million Btu heat
input, the allowance allocation is premised upon an emission rate of 1.2 pounds
at 1985 utilization levels as of the Phase II deadline of January 1, 2000; if a
unit emitted sulfur dioxide in 1985 at a rate of less than 1.2 pounds, the
allowance allocation is in most instances premised upon the actual 1985
emission rate.


   The Acid Rain Title also contains provisions concerning nitrogen oxides
emissions.  In March 1994, Federal EPA issued final regulations governing
nitrogen oxides emissions from tangentially fired and dry bottom wall-fired
boilers at Phase I units which were appealed to the U.S. Court of Appeals for
the District of Columbia Circuit by APCo, CSPCo, I&M, KEPCo and OPCo and a
group of unaffiliated utilities based on the failure of Federal EPA to
correctly define low NOx burner technology.  On November 29, 1994, the court
remanded the rules to Federal EPA and on April 13, 1995, Federal EPA issued
revised regulations pursuant to the court's remand.  Compliance with these
emission limitations is determined on an annual basis beginning in 1996.
OPCo's Mitchell Units 1 & 2 and CSPCo's Conesville Units 3 & 4 and Picway Unit
5 are Phase I units subject to these regulations.


   On January 19, 1996, Federal EPA published proposed Nox emission limitations
in the FEDERAL REGISTER for wet bottom wall-fired boilers, cyclone boilers,
units applying cell burner technology and all other types of boilers.  These
proposed emission limitations are purported to be comparable in cost to the
controls applicable to tangentially fired boilers and non-cell burner dry
bottom wall-fired boilers.  These emission limitations are required to be met
by Phase II-affected sources after January 1, 2000.  Also on January 19, 1996,
Federal EPA published proposed revisions to the existing emission limitations
for tangentially fired and dry bottom wall-fired boilers.  Federal EPA must
take final action on the proposed revisions by January 1, 1997.   These
limitations are expected to be more restrictive than those which are currently
applicable.


   The CAAA contain additional provisions, other than the Acid Rain Title,
which could require reductions in emissions of nitrogen oxides from fossil
fuel-fired power plants.  Title I, dealing generally with non-attainment of
ambient air quality standards, establishes a tiered system for classifying
degrees of non-attainment with air quality standards for ozone.  Depending upon
the severity of non-attainment within a given non-attainment area, reductions
in nitrogen oxides emissions from fossil fuel-fired power plants may be
required as part of a state's plan for achieving attainment with ozone air
quality standards.  On February 25, 1994, the West Virginia Division of
Environmental Protection issued a consent order for APCo's Amos Units 1 and 2,
requiring reductions in nitrogen oxides emissions from these units after June
1, 1995.  The reduction in nitrogen oxides emissions will be less than that
required under Title IV of the CAAA but will be required at an earlier time.
On September 6, 1994, Federal EPA officially redesignated Putnam, Wood and
Kanawha counties to ozone attainment.  West Virginia does not plan to impose
Nox reduction requirements under Title I of the CAAA as part of its ozone
maintenance plan in any of the five former moderate ozone non-attainment
counties, barring any other mandate from Federal EPA to do so.  While ozone
non-attainment is largely restricted to urban areas, AEP System generating
stations could be determined to be affecting ozone concentrations and may
therefore, eventually be required to reduce nitrogen oxides emissions pursuant
to Title I.


   In addition, certain environmental organizations and northeastern states
have filed comments with Federal EPA contending that nitrogen oxides emissions
from the midwest must be reduced in order to achieve the National Ambient Air
Quality Standard for ozone in the northeast.  Similar comments have been filed
by these organizations and others with the FERC in connection with the proposed
rulemaking involving open access to transmission facilities.  See TRANSMISSION
SERVICES - TRANSMISSION SERVICES FOR NON-AFFILIATES.  All AEP coal-fired plants
are potentially subject to the imposition of additional emission controls
resulting from these initiatives.  The Environmental Council of States formed
the Ozone Transport Assessment Group (OTAG) in early 1995 to develop estimates
of levels of reduction in volatile organic compound and/or nitrogen oxides
emissions required for significant reductions in ozone concentrations in the
eastern United States.  OTAG, consisting of the environmental commissioners and
air directors of 37 eastern states, Federal EPA and representatives from
environmental and industry groups, is currently scheduled to complete modeling
and technical work by the fall of 1996 - with evaluation of technical findings
and recommendations on regional emission controls to be submitted to Federal
EPA by January 1997.  The cost of meeting Nox emissions reduction requirements
which might be imposed to achieve the ozone ambient air quality standard cannot
be precisely predicted but could be substantial.


   Utility boilers are potentially subject to additional control requirements
under Title III of the CAAA governing hazardous air pollutant emissions.
Federal EPA is directed to conduct studies concerning the potential public
health impacts of pollutants identified by the legislation as hazardous in
connection with their emission from electric utility steam generating units.
Federal EPA was required to report the results of this study to Congress by
November 1993 and is required to regulate emissions of these pollutants from
electric utility steam generating units if it is determined that such
regulation is necessary and appropriate, based on the results of the study.
Federal EPA informed Congress that completion of this study has been delayed
significantly beyond the November 1993 deadline.  Federal EPA is subject to a
judicial consent decree requiring completion of the study and submission of it
by April 15, 1996.  Additionally, Federal EPA is directed to study the
deposition of hazardous pollutants to the Great Lakes, the Chesapeake Bay, Lake
Champlain and other coastal waters.  As part of this assessment, Federal EPA is
authorized to adopt regulations to prevent serious adverse effects to public
health and serious or widespread environmental effects.  It is possible that
emissions from electric utility steam generating units may be regulated under
this water body deposition assessment program.


   The CAAA expand the enforcement authority of the Federal government by
increasing the range of civil and criminal penalties for violations of the
Clean Air Act and enhancing administrative civil provisions, adding a citizen
suit provision and imposing a national operating permit system, emission fee
program and enhanced monitoring, record keeping and reporting requirements for
existing and new sources.


   ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN:  In 1992, the PUCO approved
a system-wide Phase I Acid Rain Program compliance plan.  The AEP System's
compliance plan centers around the compliance method selected for OPCo's two-
unit 2,600-megawatt Gavin Plant which was emitting about 25% of the System's
total sulfur dioxide emissions.  Under an Ohio law, utilities could obtain
advance PUCO approval of a least-cost compliance plan which would be deemed
prudent in subsequent PUCO rate proceedings.


   The PUCO approved least-cost plan set forth compliance measures for the
System's affected generating units, which included (i) installing leased flue
gas desulfurization equipment (scrubbers) to burn Ohio high-sulfur coal at
Gavin and (ii) designating Gavin's coal supply sources to include the
affiliated Meigs mine at a reduced operating capacity and under predetermined
prices, new long-term contracts with unaffiliated sources and spot market
purchases.


   Pursuant to a settlement agreement approved by the PUCO in connection with
OPCo's rate case discussed in RATES - OPCO, the PUCO reaffirmed its approval of
the compliance plan, which does not seek to fuel switch Cardinal Unit 1 or
Muskingum River Units 1-4 to low-sulfur coal at the beginning of Phase I of the
CAAA.  Under the terms of the compliance plan, OPCo's Muskingum River Unit 5
has been switched to low-sulfur coal.  CSPCo's Conesville Units 1-3 have been
modified to enable these units to burn coal or natural gas to comply.  Actual
fuel choice will depend on the cost and availability of gas.  Although the
compliance plan originally contemplated that CSPCo's Picway Unit 5 also would
be modified to enable this unit to burn coal or natural gas to comply, this
proposed modification has been indefinitely deferred.  Beckjord Unit 6 (owned
with CG&E and DP&L) has been switched to moderate sulfur coal.  I&M's Tanners
Creek Unit 4 has also been switched to moderate sulfur coal and I&M's Breed
Plant was retired in 1994. Eight additional units are subject to Phase I rules,
but no operating or fuel changes are planned, because they will hold allowances
sufficient for compliance.


   Since the approved plan reflects fuel switching to comply at OPCo's
Muskingum River Plant and Cardinal Unit 1, mining operations at OPCo's wholly-
owned coal-mining subsidiaries, Central Ohio Coal Company and Windsor Coal
Company, could be shut down resulting in substantial costs.  Central Ohio Coal
Company and Windsor Coal Company supply coal to Muskingum River Plant and
Cardinal Plant, respectively.


   As a result of the aforementioned PUCO approval of OPCo's least-cost
compliance plan, OPCo entered into an agreement in 1992 for construction and
lease of the Gavin Plant scrubbers with JMG Funding, Limited Partnership (JMG),
an unaffiliated entity.  The scrubbers on Gavin Units 1 and 2 commenced
operation in December 1994 and March 1995, respectively.  On March 15, 1995,
OPCo began to lease the scrubbers from JMG.  See CONSTRUCTION PROGRAM -
CONSTRUCTION EXPENDITURES.


   Recovery of compliance costs has been and will be sought through the rate-
making process.  The aforementioned OPCo settlement agreement provides, among
other things, for OPCo to recover the annual lease cost of the scrubbers and
other compliance costs and provides OPCo with an opportunity to recover its
Ohio jurisdictional share of its investment in and the liabilities and closing
costs of the affiliated Central Ohio and Windsor mining operations to the
extent the actual cost of coal burned at the Gavin Plant is below a
predetermined price.  AEP intends to also seek timely recovery of all
compliance costs, including mine shutdown costs, from its non-Ohio
jurisdictional customers.  OPCo's non-Ohio jurisdictional portion of shutdown
costs for these mines, which includes the investment in the mines, leased asset
buy-outs, reclamation costs and employee benefits is estimated to be
approximately $195,000,000 net of tax at December 31, 1995.  There can be no
assurance that regulators will provide for recovery of all CAAA compliance
costs.  Compliance with the CAAA, including potential mine closure costs, could
have an adverse effect on results of operations and possibly financial
condition unless the costs can be recovered from ratepayers and/or from asset
dispositions.


   GLOBAL CLIMATE CHANGE:  Increasing concentrations of "greenhouse gases,"
including carbon dioxide (CO{2}), in the atmosphere have led to concerns about
the potential for the earth's climate to change in ways that could result in
adverse human health effects, destruction of sensitive ecosystems, inundated
low-lying areas caused by sea-level rise, shifts in agricultural production and
other serious environmental consequences.  The proponents of this view maintain
that rising levels of greenhouse gas emissions will cause some of the sun's
energy that is normally radiated back into space to be trapped in the
atmosphere, warming the biosphere and triggering these detrimental effects.


   At the Earth Summit in Rio de Janeiro, Brazil in June 1992, 165 nations,
including the United States, signed a global climate change treaty.  Each
country that ratifies the treaty commits itself to a process of achieving the
aim of reducing greenhouse gas emissions, including CO{2}, to their 1990 level
by the year 2000.  On October 7, 1992, the U.S. Senate ratified the treaty.
The treaty went into effect on March 21, 1994.  In April 1995, the first
meeting of the nations that have ratified was held.  The parties declared that
the existing commitments under the treaty are not adequate to address the
threat of global climate change and authorized the immediate commencement of
negotiations on a protocol or other legal instrument for emission controls in
the post-2000 period.  The protocol or other legal instrument is required to
set forth "policies and measures," and "quantified limitation and reduction
objectives within specified time frames, such as 2005, 2010 and 2020" to be
adopted by signatory nations.  The negotiations are expected to be complete in
early 1997.


   In accordance with the obligations set forth in the global climate change
treaty, on April 21, 1993, President Clinton committed the United States to
reducing greenhouse gas emissions to 1990 levels by the year 2000.  On October
19, 1993, the President unveiled the Administration's Climate Change Action
Plan for meeting this emission reduction target.  The plan emphasizes
reductions in fossil fuel use, the largest source of CO{2} emissions, primarily
through reliance on voluntary energy efficiency programs and partnerships
between the Federal government and U.S. industry.  One such collaboration is
between the electric utility industry and DOE.  Known as the Climate Challenge,
this initiative has identified flexible, cost-effective measures to reduce,
avoid or sequester future greenhouse gas emissions.  AEP System companies
joined with nearly 800 investor-owned, municipal, rural electric cooperative
and Federal utilities in a voluntary agreement signed with DOE on April 20,
1994 that has led to individual utility Participation Accords resulting in
substantial reductions in future greenhouse gas emissions.  On February 3,
1995, the AEP System entered into its Climate Challenge Participation Accord
with DOE.  The Accord contains a diverse portfolio of supply-side, demand-side
and forest management/tree planting activities that will be undertaken on the
AEP System between now and the year 2000 with a projected reduction in CO{2}
emissions of 9,550,000 tons from what would have otherwise been emitted but for
these actions.


   As a result of the AEP System's historical practice of using low-cost
indigenous coal supplies to produce electricity, AEP System power plants are
significant sources of CO{2} emissions.  Management is working to support
further efforts to properly study the issue of global climate change to define
the extent, if any, to which it poses a threat to the environment.  Management
is concerned that new laws may be passed or new regulations promulgated without
sufficient scientific study and support.


   Since the AEP System is a major emitter of carbon dioxide, its financial
condition and results of operations could be materially adversely affected by
the imposition of stringent command-and-control limitations on CO{2} emissions
if the compliance costs incurred are not fully recovered from ratepayers.  In
addition, any such severe program to stabilize or reduce CO{2} emissions could
impose substantial costs on industry and society and seriously erode the
economic base that AEP's operations serve.


   WEST VIRGINIA:  West Virginia promulgated sulfur dioxide limitations which
Federal EPA approved in February 1978.  The emission limitations for the
Mitchell Plant have been approved by Federal EPA for primary ambient air
quality (health-related) standards only.  West Virginia is obliged to reanalyze
sulfur dioxide emission limits for the Mitchell Plant with respect to secondary
ambient air quality (welfare-related) standards.  Because the Clean Air Act
provides no specific deadline for approval of emission limits to achieve
secondary ambient air quality standards, it is not certain when Federal EPA
will take dispositive action regarding the Mitchell Plant.


   West Virginia has had a request to increase the sulfur dioxide emission
limitation for Kammer pending before Federal EPA for many years, although the
change has not been acted upon by Federal EPA.  On August 4, 1994, however,
Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was
operating in violation of the applicable federally enforceable sulfur dioxide
emission limit.  See Item 3. LEGAL PROCEEDINGS - KAMMER PLANT.  A portion of
the Notice of Violation relating to compliance has been resolved.  Separate
proceedings have been initiated by OPCo with both the West Virginia Division of
Environmental Protection and Region III, Federal EPA in an effort to obtain
approval for utilization of the existing fuel supply beyond the current final
compliance date of May 15, 1996.  While it is likely that the May 15, 1996
final compliance date will be extended, management cannot predict at this time
how long it will be able to utilize the existing fuel supply at the Kammer
Plant.


   STACK HEIGHT REGULATIONS:  On June 27, 1985, Federal EPA issued stack height
regulations pursuant to an order of the United States Court of Appeals for the
District of Columbia Circuit.  These regulations were appealed by a number of
states, environmental groups and investor-owned electric utilities (including
APCo, CSPCo, I&M, KEPCo and OPCo), along with three electric utility trade
associations.  OPCo also filed a separate petition for review to raise issues
unique to its Kammer Plant.  Various petitions for reconsideration filed with
and denied by Federal EPA were also appealed.  This litigation was consolidated
into a single case.


   On January 22, 1988, the U.S. Court of Appeals issued a decision in part
upholding the June 1985 stack height rules and remanding certain of the June
1985 rules to Federal EPA for further consideration.  With respect to Kammer
Plant, the January 1988 court decision rejected OPCo's appeal, holding that
Federal EPA acted lawfully in revoking stack height credit previously granted
for Kammer Plant in October 1982.  As discussed above, OPCo has also commenced
administrative proceedings with the State of West Virginia and Federal EPA in
an effort to preserve stack height credit for Kammer Plant.


   While it is not possible to state with particularity the ultimate impact of
the final rules on AEP System operations, at present it appears that the most
likely AEP System plants at which the final rules could possibly result in more
stringent emission limitations are CSPCo's Conesville Plant, AEGCo's and I&M's
Rockport Plant, I&M's Tanners Creek Plant and OPCo's Gavin and Kammer plants.
Gavin and Rockport plants were not affected by Federal EPA's stack height rules
as issued in June 1985.  However, the provision exempting these plants was
remanded to Federal EPA in the January 1988 court decision.  Accordingly, the
ultimate impact of the stack height rules on Gavin and Rockport plants will not
be known until Federal EPA completes administrative proceedings on remand and
reissues final stack height rules.  OPCo and AEGCo and I&M intend to
participate in the remand rulemaking affecting Gavin and Rockport plants,
respectively.


   State air pollution control agencies will be required to implement the stack
height rules by revising emission limitations for sources subject to the rules
and submitting such revisions to Federal EPA.


   On June 1, 1989, Ohio EPA adopted a rule concerning CSPCo's Conesville Plant
in response to Federal EPA's stack height rules adopted in 1985.  Under Federal
EPA policy published in January 1988, emission reductions required by the stack
height rules may be obtained at plants other than the plant directly affected
by the rules, and thereafter credited to the directly affected plant.  Under
Ohio EPA's June 1 rule, the sulfur dioxide emission limitations for Conesville
Units 5 and 6 remain at 1.2 pounds sulfur dioxide per million Btu heat input as
long as the emission rate at CSPCo's retired Poston Units 1-4 remains at 0.0
pounds sulfur dioxide per million Btu heat input.  Federal EPA has yet to take
action concerning Ohio EPA's June 1 rule.


   ADMINISTRATIVE DEVELOPMENTS REGARDING SULFUR DIOXIDE:  On November 15, 1994,
Federal EPA published a notice in the FEDERAL REGISTER proposing to retain the
present 24-hour national ambient air quality standard for sulfur dioxide.
Federal EPA also sought comment on the need to adopt additional regulations to
address short-term peak exposures to sulfur dioxide.  Federal EPA is soliciting
comments on three alternatives, including the adoption of a short-term standard
averaged over a five-minute period. Adoption of any of these proposed
approaches, or other targeted programs, could require substantial reductions in
sulfur dioxide emissions from the System's coal-fired generating plants which
would entail substantial capital and operating costs.  In a related action,
Federal EPA, on March 7, 1995, proposed requirements for implementing
strategies to reduce short-term (five-minute) peak concentrations of sulfur
dioxide in order to reduce health risks to exercising asthmatics.  The effect
on AEP operations of Federal EPA's proposed risk-based targeting strategies for
further regulating sulfur dioxide emissions, if finalized, cannot be predicted,
but may be significant.  Federal EPA is expected to take final action on these
proposals in the spring of 1996.


   LIFE EXTENSION:  On July 21, 1992, Federal EPA published final regulations
in the FEDERAL REGISTER governing application of new source rules to generating
plant repairs and pollution control projects undertaken to comply with the
Clean Air Act Amendments of 1990.  Generally, the rule provides that plants
undertaking pollution control projects will not trigger new source review
requirements.  The Natural Resources Defense Council and a group of utilities,
including five AEP System companies, have filed petitions in the U.S. Court of
Appeals for the District of Columbia Circuit seeking a review of the
regulations.


   OTHER REGULATORY DEVELOPMENTS:  Federal EPA is considering whether the
National Ambient Air Quality Standard for ozone should be revised and is
currently expected to make a final decision on this issue in 1997.


   Federal EPA is also considering revision of the National Ambient Air Quality
Standard for particulate matter.  Federal EPA is required by court order to
make a final determination on this issue by June 28, 1997.


   WATER POLLUTION CONTROL


   Under the Clean Water Act, effluent limitations requiring application of the
best available technology economically achievable are to be applied, and those
limitations require that no pollutants be discharged if Federal EPA finds
elimination of such discharges is technologically and economically achievable.


   The Clean Water Act provides citizens with a cause of action to enforce
compliance with its pollution control requirements.  Since 1982, many such
actions against NPDES permit holders have been filed.  To date, no AEP System
plants have been named in such actions.


   All System Plants are operating with NPDES permits.  Under EPA's
regulations, operation under an expired NPDES permit is authorized provided an
application is filed at least 180 days prior to expiration.  Renewal
applications are being prepared or have been filed for renewal of NPDES permits
which expire in 1996.


   The NPDES permits generally require that certain thermal impact study
programs be undertaken.  These studies have been completed for all System
plants. Thermal variances are in effect for all plants with once-through
cooling water.  The thermal variances for Conesville and Muskingum River plants
impose thermal management conditions that could result in load curtailment
under certain conditions, but the cost impacts are not expected to be
significant.  Based on favorable results of in-stream biological studies, OPCo
has requested a modification of the thermal management plan in the renewed
permit for Muskingum River expected to be issued this year.


   Certain mining operations conducted by System companies as discussed under
FUEL SUPPLY are also subject to Federal and state water pollution control
requirements, which may entail substantial expenditures for control facilities,
not included at present in the System's construction cost estimates set forth
herein.  See Item 3. LEGAL PROCEEDINGS - MEIGS MINE with respect to litigation
regarding certain discharges from OPCo's Meigs 31 mine.


   The Federal Water Quality Act of 1987 requires states to adopt stringent
water quality standards for a large category of toxic pollutants and to
identify specialized control measures for dischargers to waters where water
quality standards are not being met.  Implementation of these provisions could
result in significant costs to the AEP System if biological monitoring
requirements and water quality-based effluent limits are placed in NPDES
permits.


   In March 1995, Federal EPA finalized a set of rules which establish minimum
water quality standards, anti-degradation policies and implementation
procedures for more stringently controlling releases of toxic pollutants into
the Great Lakes system.  This regulatory package is called the Great Lakes
Water Quality Initiative (GLWQI).  The most direct compliance cost impact could
be related to I&M's Cook Plant.  Management cannot presently determine whether
the GLWQI would have a significant adverse impact on AEP operations.  The
significance of such impact will depend on the outcome of Federal EPA's policy
on intake credits and site specific variables as well as Michigan's
implementation strategy.  Federal EPA's rule is presently under review by the
District of Columbia Circuit Court of Appeals in litigation initiated by
several industry groups.  If Indiana and Ohio eventually adopt the GLWQI
criteria for statewide application, AEP System plants located in those states
could also be affected.


   HAZARDOUS SUBSTANCES AND WASTES


   Section 311 of the Clean Water Act imposes substantial penalties for spills
of Federal EPA-listed hazardous substances into water and for failure to report
such spills.  The Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) expanded the reporting requirements to cover the release
of hazardous substances generally into the environment, including water, land
and air.  AEP's subsidiaries store and use some of these hazardous substances,
including PCB's contained in certain capacitors and transformers, but the
occurrence and ramifications of a spill or release of such substances cannot be
predicted.


   CERCLA provides governmental agencies with the authority to require clean-up
of hazardous waste sites and releases of hazardous substances into the
environment.  Since liability under CERCLA is strict and can be applied
retroactively, AEP System companies which previously disposed of PCB-containing
electrical equipment and other hazardous substances may be required to
participate in remedial activities at such disposal sites should environmental
problems result.  AEP System companies are presently identified by Federal EPA
as potentially responsible parties (PRPs) for cleanup of seven federal sites,
including I&M at four sites, KEPCo at one site, OPCo at one site, and Wheeling
Power Company at one site.  OPCo is a defendant in a cost recovery suit for the
site where OPCo is a PRP and at two additional CERCLA sites.  I&M is a
defendant in a cost recovery action at one of the sites where I&M is a PRP and
for one additional CERCLA site.  APCo and I&M each have been named as parties
potentially responsible at a state remediation site.  Management's present
estimates do not anticipate material cleanup costs for identified sites for
which AEP subsidiaries have been declared PRPs.  However, if for reasons not
currently identified significant costs are incurred for cleanup, future results
of operations and possibly financial condition would be adversely affected
unless the costs can be recovered through rates.


   Regulations issued by Federal EPA under the Toxic Substances Control Act
govern the use, distribution and disposal of PCBs, including PCBs in electrical
equipment.  Deadlines for removing certain PCB-containing electrical equipment
from service have been met.


   In addition to handling hazardous substances, the System companies generate
solid waste associated with the combustion of coal, the vast majority of which
is fly ash, bottom ash and flue gas desulfurization wastes.  These wastes
presently are considered to be non-hazardous under RCRA and applicable state
law and the wastes are treated and disposed in surface impoundments or
landfills in accordance with state permits or authorization or beneficially
utilized.  As required by RCRA, EPA evaluated whether high volume coal
combustion wastes (such as fly ash, bottom ash and flue gas desulfurization
wastes) should be regulated as hazardous waste.  In August, 1993 EPA issued a
regulatory determination that such high volume coal combustion wastes should
not be regulated as hazardous waste.  For low volume coal combustion wastes,
such as metal and boiler cleaning wastes, Federal EPA will gather additional
information and make a regulatory determination by April 1998.  Until that
time, these low volume wastes are provisionally excluded from regulation under
the hazardous waste provisions of RCRA.  All presently generated hazardous
waste is being disposed of at permitted off-site facilities in compliance with
applicable Federal and state laws and regulations.  For System facilities which
generate such wastes, System companies have filed the requisite notices and are
complying with RCRA and applicable state regulations for generators.  Nuclear
waste produced at the Cook Plant regulated under the Atomic Energy Act is
excluded from regulation under RCRA.


   Federal EPA's technical requirements for underground storage tanks
containing petroleum will require retrofitting or replacement of an appreciable
number of tanks.  Compliance costs for tank replacement and site remediation
have not been significant to date.


   ELECTRIC AND MAGNETIC FIELDS (EMF)


   EMF is found everywhere there is electricity.  Electric fields are created
by the presence of electric charges.  Magnetic fields are produced by the flow
of those charges. This means that EMF is created by electricity flowing in
transmission and distribution lines, or being used in household wiring and
appliances.


   A number of studies in the past several years have examined the possibility
of adverse health effects from EMF.  While some of the epidemiological studies
have indicated some association between exposure to EMF and health effects, the
majority of studies have indicated no such association.  The epidemiological
studies that have received the most public attention reflect a weak correlation
between surrogate or indirect estimates of EMF exposure and certain cancers.
Studies using direct measurements of EMF exposure show no such association.


   There were two residential epidemiological studies of childhood brain cancer
published in early 1996 which showed no association with EMF exposure.
Research to date has not shown any causal relationship between EMF exposure and
cancer, or any other adverse health effects.  Additional studies, which are
intended to provide a better understanding of the subject, are continuing.


   Federal EPA is currently studying whether exposure to EMF is associated with
cancer in humans. In 1990, Federal EPA issued a draft report on EMF, received
interagency review and public comment, and is in the process of preparing its
final report.  A December 1992 brochure from Federal EPA, QUESTIONS AND ANSWERS
ABOUT ELECTRIC AND MAGNETIC FIELDS (EMFS), states at page 3, "The bottom line
is that there is no established cause and effect relationship between EMF
exposure and cancer or other disease."


   The Energy Policy Act of 1992 established a coordinated Federal EMF research
program.  The program funding is $65,000,000 over five years, half of which is
to be provided by private parties including utilities.  AEP has committed to
contribute $446,571 over the five-year period.


   AEP's participation is a continuation of its efforts to support further
research and to communicate with its customers and employees about this issue.
Its operating company subsidiaries provide their residential customers with
information and field measurements on request, although there is no scientific
basis for interpreting such measurements.


   A number of lawsuits based on EMF-related grounds have been filed in recent
years against electric utilities.  A suit was filed on May 23, 1990 against I&M
involving claims that EMF from a 345 KV transmission line caused adverse health
effects.  No specific amount has been requested for damages in this case and no
trial date has been set.


   Some states have enacted regulations to limit the strength of magnetic
fields at the edge of transmission line rights-of-way.  No state which the AEP
System serves has done so.  In March 1993, The Ohio Power Siting Board issued
its amended rules providing for additional consideration of the possible
effects of EMF in the certification of electric transmission facilities.  Under
the amended EMF rules, persons seeking approval to build electric transmission
lines have to provide estimates of EMF from transmission lines under a variety
of conditions.  In addition, applicants are required to address possible health
effects and discuss the consideration of design alternatives with respect to
EMF.


   In April 1993, the State of Indiana enacted a law which provides that the
IURC shall determine, based on the preponderance of evidence in the scientific
literature, whether rules are necessary to protect the public health from EMF.
If the IURC determines that such rules are necessary, the IURC is required to
adopt rules that reasonably protect the public health from EMF.


   Management cannot predict the ultimate impact of the question of EMF
exposure and adverse health effects.  If further research shows that EMF
exposure contributes to increased risk of cancer or other health problems, or
if the courts conclude that EMF exposure harms individuals and that utilities
are liable for damages, or if states limit the strength of magnetic fields to
such a level that the current electricity delivery system must be significantly
changed, then the results of operations and financial condition of AEP and its
operating subsidiaries could be materially adversely affected unless these
costs can be recovered from ratepayers.

RESEARCH AND DEVELOPMENT


   AEP and its subsidiaries are involved in a number of research projects which
are directed toward developing more efficient methods of burning coal, reducing
the contaminants resulting from combustion of coal, and improving the
efficiency and reliability of power transmission, distribution and utilization,
including load management.


   AEP System operating companies are members of the Electric Power Research
Institute (EPRI), a nonprofit organization that manages research and
development on behalf of the U.S. electric utility industry.  EPRI, founded in
1973, manages technical research and development programs for its members to
improve power production, delivery and use.  Approximately 700 utilities are
members.  EPRI has agreed to a membership program with AEP whereby dues are
being phased in from 1994 through 1996.  Recovery of these dues through rates
by AEP's operating companies has reasonably coincided with their phase-in
dates.  It is anticipated that recovery of the final 1996 dues phase-in will be
sought in future rate cases.
<PAGE>

   Total research and development expenditures by AEP and its subsidiaries were
approximately $19,300,000 for the year ended December 31, 1995, $7,600,000 for
the year ended December 31, 1994 and $13,800,000 for the year ended December
31, 1993.  This includes expenditures of $6,700,000 for 1995, $2,200,000 for
1994 and $10,900,000 for 1993 related to pressurized fluidized-bed combustion,
a process in which sulfur is removed during coal combustion and nitrogen oxide
formation is minimized.  EPRI dues of $9,600,000 for 1995 and $3,200,000 for
1994 are also included.




Item 2.  PROPERTIES



   At December 31, 1995, subsidiaries of AEP owned (or leased where indicated)
generating plants with the net power capabilities (winter rating) shown in the
following table:

<TABLE>
<CAPTION>
                                                                      NET KILOWATT
OWNER, PLANT TYPE AND NAME             LOCATION (NEAR)                 CAPABILITY
<S>                                    <C>                            <C>
AEP GENERATING COMPANY:

Steam - Coal-Fired:
   Rockport Plant (AEGCo share)        Rockport, Indiana              1,300,000(a)


APPALACHIAN POWER COMPANY:

Steam - Coal-Fired:
   John E. Amos, Units 1 & 2           St. Albans, West Virginia      1,600,000
   John E. Amos, Unit 3 (APCo share)   St. Albans, West Virginia        433,000(b)
   Clinch River                        Carbo, Virginia                  705,000
   Glen Lyn                            Glen Lyn, Virginia               335,000
   Kanawha River                       Glasgow, West Virginia           400,000
   Mountaineer                         New Haven, West Virginia       1,300,000
   Philip Sporn, Units 1 & 3           New Haven, West Virginia         308,000

Hydroelectric - Conventional:
   Buck                                Ivanhoe, Virginia                 10,000
   Byllesby                            Byllesby, Virginia                20,000
   Claytor                             Radford, Virginia                 76,000
   Leesville                           Leesville, Virginia               40,000
   London                              Montgomery, West Virginia         16,000
   Marmet                              Marmet, West Virginia             16,000
   Niagara                             Roanoke, Virginia                  3,000
   Reusens                             Lynchburg, Virginia               12,000
   Winfield                            Winfield, West Virginia           19,000

Hydroelectric - Pumped Storage:
   Smith Mountain                      Penhook, Virginia                565,000

                                                                      5,858,000

COLUMBUS SOUTHERN POWER COMPANY:

Steam - Coal-Fired:
   Beckjord, Unit 6                    New Richmond, Ohio                53,000(c)
   Conesville, Units 1-3, 5 & 6        Coshocton, Ohio                1,165,000
   Conesville, Unit 4                  Coshocton, Ohio                  339,000(c)
   Picway, Unit 5                      Columbus, Ohio                   100,000
   Stuart, Units 1-4                   Aberdeen, Ohio                   608,000(c)
   Zimmer                              Moscow, Ohio                     330,000(c)

                                                                      2,595,000

INDIANA MICHIGAN POWER COMPANY:

Steam - Coal-Fired:
   Rockport Plant (I&M share)          Rockport, Indiana              1,300,000(a)
   Tanners Creek                       Lawrenceburg, Indiana            995,000

Steam - Nuclear:
   Donald C. Cook                      Bridgman, Michigan             2,110,000

Gas Turbine:
   Fourth Street                       Fort Wayne, Indiana               18,000(d)

Hydroelectric - Conventional:
   Berrien Springs                     Berrien Springs, Michigan          3,000
   Buchanan                            Buchanan, Michigan                 2,000
   Constantine                         Constantine, Michigan              1,000
   Elkhart                             Elkhart, Indiana                   1,000
   Mottville                           Mottville, Michigan                1,000
   Twin Branch                         Mishawaka, Indiana                 3,000

                                                                      4,434,000
KENTUCKY POWER COMPANY:

Steam - Coal-Fired:
      Big Sandy                        Louisa, Kentucky               1,060,000

OHIO POWER COMPANY:

Steam - Coal-Fired:
   John E. Amos, Unit 3 (OPCo share)   St. Albans, West Virginia        867,000(b)
   Cardinal, Unit 1                    Brilliant, Ohio                  600,000
   General James M. Gavin              Cheshire, Ohio                 2,600,000(e)
   Kammer                              Captina, West Virginia           630,000
   Mitchell                            Captina, West Virginia         1,600,000

Steam - Coal-Fired:
   Muskingum River                     Beverly, Ohio                  1,425,000
   Philip Sporn, Units 2, 4 & 5        New Haven, West Virginia         742,000

Hydroelectric - Conventional:
   Racine                              Racine, Ohio                      48,000

                                                                      8,512,000

                                  Total Generating Capability        23,759,000
SUMMARY:

Total Steam -
   Coal-Fired                                                        20,795,000
   Nuclear                                                            2,110,000

Total Hydroelectric -
   Conventional                                                         271,000
   Pumped Storage                                                       565,000
   Other                                                                 18,000

Total Generating Capability                                          23,759,000


</TABLE>
(a)Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M.
   Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by
   I&M.  The leases terminate in 2022 unless extended.
(b)Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds
   by OPCo.
(c)Represents CSPCo's ownership interest in generating units owned in common
   with CG&E and DP&L.
(d)Leased from the City of Fort Wayne, Indiana.  Since 1975, I&M has leased and
   operated the assets of the municipal system of the City of Fort Wayne,
   Indiana under a 35-year lease with a provision for an additional 15-year
   extension at the election of I&M.
(e)The scrubber facilities at the Gavin Plant are leased.  The lease terminates
   in 2010 unless extended.

  See Item 1 under FUEL SUPPLY, for information concerning coal reserves owned
or controlled by subsidiaries of AEP.


  The following table sets forth the total circuit miles of transmission and
distribution lines of the AEP System, APCo, CSPCo, I&M, KEPCo and OPCo and that
portion of the total representing 765,000-volt lines:


                 TOTAL CIRCUIT MILES
                 OF TRANSMISSION AND     CIRCUIT MILES OF
                 DISTRIBUTION LINES     765,000-VOLT LINES


AEP System (a)       125,545(b)                2,022
APCo                  48,961                     641
CSPCo (a)             14,710                     ---
I&M                   20,784                     614
KEPCo                  9,944                     258
OPCo                  28,286                     509


(a) Includes 766 miles of 345,000-volt jointly owned lines.
(b) Includes lines of other AEP System companies not shown.

TITLES


   The AEP System's electric generating stations are generally located on lands
owned in fee simple.  The greater portion of the transmission and distribution
lines of the System has been constructed over lands of private owners pursuant
to easements or along public highways and streets pursuant to appropriate
statutory authority.  The rights of the System in the realty on which its
facilities are located are considered by it to be adequate for its use in the
conduct of its business.  Minor defects and irregularities customarily found in
title to properties of like size and character may exist, but such defects and
irregularities do not materially impair the use of the properties affected
thereby.  System companies generally have the right of eminent domain whereby
they may, if necessary, acquire, perfect or secure titles to or easements on
privately-held lands used or to be used in their utility operations.


   Substantially all the physical properties of APCo, CSPCo, I&M, KEPCo and
OPCo are subject to the lien of the mortgage and deed of trust securing the
first mortgage bonds of each such company.

SYSTEM TRANSMISSION LINES AND FACILITY SITING


   Legislation in the states of Indiana, Kentucky, Michigan, Ohio, Virginia,
and West Virginia requires prior approval of sites of generating facilities
and/or routes of high-voltage transmission lines.  Delays and additional costs
in constructing facilities have been experienced as a result of proceedings
conducted pursuant to such statutes, as well as in proceedings in which
operating companies have sought to acquire rights-of-way through condemnation,
and such proceedings may result in additional delays and costs in future years.

PEAK DEMAND


   The AEP System is interconnected through 120 high-voltage transmission
interconnections with 29 neighboring electric utility systems.  The all-time
and 1995 one-hour peak System demands were 25,940,000 and 24,888,000 kilowatts,
respectively (which included 7,314,000 and 4,934,000 kilowatts, respectively,
of scheduled deliveries to unaffiliated systems which the System might, on
appropriate notice, have elected not to schedule for delivery) and occurred on
June 17, 1994 and August 15, 1995, respectively.  The net dependable capacity
to serve the System load on such date, including power available under
contractual obligations, was 23,457,000 and 23,364,000 kilowatts, respectively.
The all-time and 1995 one-hour internal peak demands were 19,557,000 and
19,516,000 kilowatts, respectively, and occurred on February 5, 1996 and August
14, 1995, respectively.  The net dependable capacity to serve the System load
on such date, including power dedicated under contractual arrangements, was
23,670,000 and 23,364,000 kilowatts, respectively.  The all-time one-hour
integrated and internal net system peak demands and 1995 peak demands for AEP's
generating subsidiaries are shown in the following tabulation:


       ALL-TIME ONE-HOUR INTEGRATED    1995 ONE-HOUR INTEGRATED
          NET SYSTEM PEAK DEMAND       NET SYSTEM PEAK DEMAND
                            (in thousands)
        Number of                    Number of
        KILOWATTS       DATE         KILOWATTS       DATE

APCo      8,214   February 5, 1996     7,327     February 6, 1995
CSPCo     4,172   June 17, 1994        4,085     August 14, 1995
I&M       5,027   June 17, 1994        4,949     August 15, 1995
KEPCo     1,686   February 5, 1996     1,512     February 6, 1995
OPCo      7,291   June 17, 1994        6,913     August 15, 1995


       ALL-TIME ONE-HOUR INTEGRATED    1995 ONE-HOUR INTEGRATED
         NET INTERNAL PEAK DEMAND      NET INTERNAL PEAK DEMAND
                             (in thousands)
        Number of                      Number of
        KILOWATTS      DATE            KILOWATTS       DATE

APCo      6,908   February 5, 1996       6,507    February 9, 1995
CSPCo     3,378   August 14, 1995        3,378    August 14, 1995
I&M       3,864   August 14, 1995        3,864    August 14, 1995
KEPCo     1,418   February 5, 1996       1,363    February 9, 1995
OPCo      5,641   August 14, 1995        5,641    August 14, 1995

HYDROELECTRIC PLANTS


   Licenses for hydroelectric plants, issued under the Federal Power Act,
reserve to the United States the right to take over the project at the
expiration of the license term, to issue a new license to another entity, or to
relicense the project to the existing licensee.  In the event that a project is
taken over by the United States or licensed to a new licensee, the Federal
Power Act provides for payment to the existing licensee of its "net investment"
plus severance damages.  Licenses for six System hydroelectric plants expired
in 1993 and applications for new licenses for these plants were filed in 1991.
The existing licenses for these plants were extended on an annual basis and
will be renewed automatically until new licenses are issued.  No competing
license applications were filed.  Four new licenses were issued in 1994.  New
licenses for two other projects, one in Indiana and one in Michigan, are still
pending before the FERC.  An original license for the previously unlicensed
Constantine project was issued in 1993.  In 1995, a notice of intent to
relicense the Elkhart project located in Indiana was filed.

COOK NUCLEAR PLANT


   Unit 1 of the Cook Plant, which was placed in commercial operation in 1975,
has a nominal net electric rating of 1,020,000 kilowatts.  Unit 1's
availability factor was 66.3% during 1995 and 71.0% during 1994.  Unit 2, of
slightly different design, has a nominal net electrical rating of 1,090,000
kilowatts and was placed in commercial operation in 1978.  Unit 2's
availability factor was 94.4% during 1995 and 54.3% during 1994.  Outages to
refuel affected the availability of Unit 1 in 1995 and Units 1 and 2 in 1994.


   Units 1 and 2 are licensed by the NRC to operate at 100% of rated thermal
power to October 25, 2014 and December 23, 2017, respectively.


   Costs associated with the operation, maintenance and retirement of nuclear
plants continue to be significant and less predictable than costs associated
with other sources of generation, in large part due to changing regulatory
requirements and safety standards and experience gained in the construction and
operation of nuclear facilities.  I&M may also incur costs and experience
reduced output at its Cook Plant because of the design criteria prevailing at
the time of construction and the age of the plant's systems and equipment.  In
addition, for economic or other reasons, operation of the Cook Plant for the
full term of its now assumed life cannot be assured.  Nuclear industry-wide and
Cook Plant initiatives have contributed to slowing the growth of operating and
maintenance costs.  However, the ability of I&M to obtain adequate and timely
recovery of costs associated with the Cook Plant, including replacement power
and retirement costs, is not assured.


   NUCLEAR INCIDENT LIABILITY


   The Price-Anderson Act limits public liability for a nuclear incident at any
licensed reactor in the United States to $8.9 billion.  I&M has insurance
coverage for liability from a nuclear incident at its Cook Plant.  Such
coverage is provided through a combination of private liability insurance, with
the maximum amount available of $200,000,000, and mandatory participation for
the remainder of the $8.9 billion liability, in an industry retrospective
deferred premium plan which would, in case of a nuclear incident, assess all
licensees of nuclear plants in the U.S.  Under the deferred premium plan, I&M
could be assessed up to $158,600,000 payable in annual installments of
$20,000,000 in the event of a nuclear incident at Cook or any other nuclear
plant in the U.S.  There is no limit on the number of incidents for which I&M
could be assessed these sums.


   I&M also has property damage, decontamination and decommissioning insurance
for loss resulting from damage to the Cook Plant facilities in the amount of
$3.6 billion.  Energy Insurance Bermuda (EIB), Nuclear Mutual Limited (NML) and
Nuclear Electric Insurance Limited (NEIL) provide $2.75 billion of coverage and
nuclear insurance pools provide the remainder.  If EIB's, NML's and NEIL's
losses exceed their available resources, I&M would be subject to a total
retrospective premium assessment of up to $33,000,000.  NRC regulations require
that, in the event of an accident, whenever the estimated costs of reactor
stabilization and site decontamination exceed $100,000,000, the insurance
proceeds must be used, first, to return the reactor to, and maintain it in, a
safe and stable condition and, second, to decontaminate the reactor and reactor
station site in accordance with a plan approved by the NRC.  The insurers then
would indemnify I&M for property damage up to $3.35 billion less any amounts
used for stabilization and decontamination.  The remaining $250,000,000, as
provided by NEIL (reduced by any stabilization and decontamination expenditures
over $3.35 billion), would cover decommissioning costs in excess of funds
already collected for decommissioning.  See FUEL SUPPLY - NUCLEAR WASTE.


   NEIL's extra-expense program provides insurance to cover extra costs
resulting from a prolonged accidental outage of a nuclear unit.  I&M's policy
insures against such increased costs up to approximately $3,500,000 per week
(starting 21 weeks after the outage) for one year, $2,800,000 per week for the
second and third years, or 80% of those amounts per unit if both units are down
for the same reason.  If NEIL's losses exceed its available resources, I&M
would be subject to a total retrospective premium assessment of up to
$7,900,000.

POTENTIAL UNINSURED LOSSES


   Some potential losses or liabilities may not be insurable or the amount of
insurance carried may not be sufficient to meet potential losses and
liabilities, including liabilities relating to damage to the Cook Plant and
costs of replacement power in the event of a nuclear incident at the Cook
Plant.  Future losses or liabilities which are not completely insured, unless
allowed to be recovered through rates, could have a material adverse effect on
results of operations and the financial condition of AEP, I&M and other AEP
System companies.
<PAGE>



Item 3.  LEGAL PROCEEDINGS




   On April 4, 1991, then Secretary of Labor Lynn Martin announced that the
U.S. Department of Labor (DOL) had issued a total of 4,710 citations to
operators of 847 coal mines who allegedly submitted respirable dust sampling
cassettes that had been altered so as to remove a portion of the dust.  The
cassettes were submitted in compliance with DOL regulations which require
systematic sampling of airborne dust in coal mines and submission of the entire
cassettes (which include filters for collecting dust particulates) to the Mine
Safety and Health Administration (MSHA) for analysis.  The amount of dust
contained on the cassette's filter determines an operator's compliance with
respirable dust standards under the law.  OPCo's Meigs No. 2, Meigs No. 31,
Martinka, and Windsor Coal mines received 16, 3, 15 and 2 citations,
respectively.  MSHA has assessed civil penalties totalling $56,900 for all
these citations.  OPCo's samples in question involve about 1 percent of the
2,500 air samples that OPCo submitted over a 20-month period from 1989 through
1991 to the DOL.  OPCo is contesting the citations before the Federal Mine
Safety and Health Review Commission.  An administrative hearing was held before
an administrative law judge with respect to all affected coal operators.  On
July 20, 1993, the administrative law judge rendered a decision in this case
holding that the Secretary of Labor failed to establish that the presence of a
"white center" on the dust sampling filter indicated intentional alteration.
In the case of an unaffiliated mine, the administrative law judge ruled on
April 20, 1994, that there was not an intentional alteration of the dust
sampling filter.  The Secretary of Labor appealed to the Federal Mine Safety
and Health Review Commission the July 20, 1993 and April 20, 1994
administrative law judge decisions and in November 1995 the Commission affirmed
these decisions.  All remaining cases, including the citations involving OPCo's
mines, have been stayed.


   On September 30, 1994, Federal EPA served APCo and Global Power Company, an
independent contractor retained by APCo, with a complaint alleging violations
of the Clean Air Act.  The complaint is based on alleged violations of the
National Emission Standard for Asbestos related to an asbestos abatement
project at APCo's Kanawha River Plant.  The complaint seeks a civil
administrative penalty of $167,500.  On October 27, 1994, APCo and Global
jointly filed an answer to this complaint and requested both a formal hearing
and informal settlement conference.


   On February 28, 1994, Ormet Corporation filed a complaint in the U.S.
District Court, Northern District of West Virginia, against AEP, OPCo, the
Service Corporation and two of its employees, Federal EPA and the Administrator
of Federal EPA.  Ormet is the operator of a major aluminum reduction plant in
Ohio and is a customer of OPCo.  See CERTAIN INDUSTRIAL CUSTOMERS.  Pursuant to
the Clean Air Act Amendments of 1990, OPCo received SO{2} Allowances for its
Kammer Plant.  See ENVIRONMENTAL AND OTHER MATTERS.  Ormet's complaint sought a
declaration that it is the owner of approximately 89% of the Phase I and Phase
II SO{2} allowances issued for use by the Kammer Plant.  On March 31, 1995, the
District Court issued an opinion and order dismissing Ormet's claims based on a
lack of jurisdiction.  On April 11, 1995, Ormet appealed the District Court's
decision to the U.S. Court of Appeals for the Fourth Circuit with respect to
the Service Corporation and OPCo only.


   See Item 1 for a discussion of certain environmental and rate matters.


   MEIGS MINE:  On July 11, 1993, water from an adjoining sealed and abandoned
mine owned by Southern Ohio Coal Company (SOCCo), a mining subsidiary of OPCo,
entered Meigs 31 mine, one of two mines currently being operated by SOCCo.
Ohio EPA approved a plan to pump water from the mine to certain Ohio River
tributaries under stringent conditions for biological and water quality
monitoring and restoring the streams after pumping.  On July 30, pumping
commenced in accordance with the Ohio EPA approved plan and, after all water
was removed from the mine, the mine was returned to service in February 1994.


   In April 1994, the U.S. Court of Appeals for the Sixth Circuit reversed the
judgement of the U.S. District Court for the Southern District of Ohio which
had granted a preliminary injunction to SOCCo preventing Federal EPA and the
Federal Office of Surface Mining, Reclamation and Enforcement (OSM) from
interfering with the removal of water from SOCCo's Meigs 31 mine.


   The West Virginia Division of Environmental Protection (West Virginia DEP)
had proposed fining SOCCo $1,800,000 for violations of West Virginia Water
Quality Standards and permitting requirements alleged to have resulted from the
release of mine water into the Ohio River.  As a result of the West Virginia
DEP proposing to fine SOCCo, SOCCo filed an action on June 1, 1994 in the U.S.
District Court for the Southern District of West Virginia seeking a
determination that the state of West Virginia has no jurisdiction to impose
penalties with respect to the mine water discharges.  SOCCo and the West
Virginia DEP have entered into a settlement agreement dated May 8, 1995, under
which the West Virginia DEP has released SOCCo from any claims which it may
have had and SOCCo has made a donation of $260,000 to the Water Quality
Management Fund of the West Virginia DEP.


   SOCCo has entered into a consent decree and settlement agreement with
Federal EPA and OSM which was lodged with the U.S. District Court, Southern
District of Ohio, on January 30, 1996 and noticed in the FEDERAL REGISTER on
February 15, 1996.  The decree and settlement agreement resolve all disputes
between SOCCo and Federal EPA and OSM over the legality of the removal of water
from SOCCo's Meigs 31 mine.  Under the terms of the settlement agreement, SOCCo
is responsible for the return of pre-pumping biological conditions in the
affected streams if those conditions do not return to pre-pumping status under
the plan previously agreed to by SOCCo and the Ohio EPA as a condition to the
pumping.  SOCCo will pay to the U.S. $1,900,000 as compensation for natural
resources alleged to have been affected by the mine dewatering.  The $1,900,000
will be used to fund Leading Creek watershed enhancement projects in three Ohio
counties.  Under the settlement agreement, SOCCo is also required to pay to the
U.S. $242,200 as reimbursement for costs incurred in monitoring and assessing
the effects of its discharge of water.  SOCCo will also pay to the U.S. a civil
penalty of $300,000.  Of this amount, $200,000 is designated as settlement for
claims under the Clean Water Act, and $100,000 is designated as settlement for
claims under the Surface Mining Control and Reclamation Act.  Finally, SOCCo
will provide $100,000 to the State of West Virginia for work in the Ohio
River for the benefit of Leading Creek on acceptance by the U.S. Fish and
Wildlife Service of an acceptable plan from the State.


   KAMMER PLANT: In August 1994, Federal EPA issued a Notice of Violation (NOV)
to OPCo alleging that its Kammer Plant has been operating in violation of
applicable federally enforceable air pollution control requirements for sulfur
dioxide since at least January 1, 1989.  The Clean Air Act provides that
Federal EPA may commence a civil action for injunctive relief and/or civil
penalties of up to $25,000 per day for each day of violation.  On November 15,
1994, a civil complaint containing the allegations included in the NOV was
filed by Federal EPA against OPCo in the U.S. District Court, Northern District
of West Virginia.  A Partial Consent Decree has been entered by the court,
extending until May 15, 1996 the date by which OPCo would need to reduce the
sulfur content of the fuel supply for Kammer.  Negotiations are in an advanced
stage to extend the final compliance date beyond May 15, 1996 and to resolve
the penalty issues raised by the civil complaint.  It is not anticipated that
the ultimate resolution of this matter will have a material adverse impact on
results of operations.


Item 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS




   AEP, APCO, I&M AND OPCO.  None.


   AEGCO, CSPCO AND KEPCO.  Omitted pursuant to Instruction J(2)(c).



EXECUTIVE OFFICERS OF THE REGISTRANTS


AEP


   The following persons are, or may be deemed, executive officers of AEP.
Their ages are given as of March 15, 1996.


NAME                 AGE                      OFFICE (a)

E. Linn Draper, Jr.  54  Chairman of the Board, President and Chief Executive
                         Officer of AEP and of the Service Corporation

Peter J. DeMaria     61  Controller of AEP; Executive Vice President-
                         Administration and Chief Accounting Officer of the
                         Service Corporation

William J. Lhota     56  Executive Vice President of the Service Corporation

Gerald P. Maloney    63  Vice President and Secretary of AEP; Executive Vice
                         President-Chief Financial Officer of the Service
                         Corporation

James J. Markowsky   51  Executive Vice President-Power Generation of the
                         Service Corporation



(a)All of the executive officers listed above have been employed by the Service
   Corporation or System companies in various capacities (AEP, as such, has no
   employees) during the past five years, except E. Linn Draper, Jr. who was
   Chairman of the Board, President and Chief Executive Officer of Gulf States
   Utilities Company from 1987 until 1992 when he joined AEP and the Service
   Corporation.  All of the above officers are appointed annually for a one-
   year term by the board of directors of AEP, the board of directors of the
   Service Corporation, or both, as the case may be.

APCO


   The names of the executive officers of APCo, the positions they hold with
APCo, their ages as of March 15, 1996, and a brief account of their business
experience during the past five years appears below.  The directors and
executive officers of APCo are elected annually to serve a one-year term.


<TABLE>
<CAPTION>
NAME                AGE                       POSITION (a)                         PERIOD
<S>                  <C>  <C>                                                    <C>
E. Linn Draper, Jr.  54   Director                                               1992-Present
                          Chairman of the Board and Chief Executive Officer      1993-Present
                          Vice President                                         1992-1993
                          Chairman of the Board, President and Chief Executive 
                            Officer of AEP and the Service Corporation           1993-Present
                          President of AEP                                       1992-1993
                          President and Chief Operating Officer of the Service
                            Corporation                                          1992-1993
                          Chairman of the Board, President and Chief Executive
                            Officer of Gulf States Utilities Company             1987-1992

Peter J. DeMaria     61   Director                                               1988-Present
                          Vice President                                         1991-Present
                          Controller                                             1995-Present
                          Treasurer                                              1978-1995
                          Controller of AEP                                      1995-Present
                          Treasurer of AEP                                       1978-1995
                          Executive Vice President-Administration and Chief
                            Accounting Officer of the Service Corporation        1984-Present
                          Treasurer of the Service Corporation                   1989-1990

William J. Lhota     56   Director                                               1990-Present
                          President and Chief Operating Officer                  1996-Present
                          Vice President                                         1989-1995
                          Executive Vice President of the Service Corporation    1993-Present
                          Executive Vice President-Operations of the Service     
                            Corporation                                          1989-1993

Gerald P. Maloney    63   Director and Vice President                            1970-Present
                          Vice President of AEP                                  1974-Present
                          Secretary of AEP                                       1994-Present
                          Executive Vice President-Chief Financial Officer of
                            the Service Corporation                              1991-Present
                          Senior Vice President-Finance of the Service
                            Corporation                                          1974-1990

James J. Markowsky   51   Director                                               1993-Present
                          Vice President                                         1995-Present
                          Executive Vice President-Power Generation of the
                            Service Corporation                                  1996-Present
                          Executive Vice President-Engineering and Construction
                            of the Service Corporation                           1993-1996
                          Senior Vice President and Chief Engineer of the
                            Service Corporation                                  1988-1993


(a) Positions are with APCo unless otherwise indicated.

OPCO


   The names of the executive officers of OPCo, the positions they hold with
OPCo, their ages as of March 15, 1996, and a brief account of their business
experience during the past five years appear below.  The directors and
executive officers of OPCo are elected annually to serve a one-year term.



</TABLE>
<TABLE>
<CAPTION>
NAME                 AGE                      POSITION (a)                        PERIOD
<S>                  <C>   <C>                                                   <C>
E. Linn Draper, Jr.  54    Director                                              1992-Present
                           Chairman of the Board and Chief Executive Officer     1993-Present
                           Vice President                                        1992-1993
                           Chairman of the Board, President and Chief Executive
                             Officer of AEP and the Service Corporation          1993-Present
                           President of AEP                                      1992-1993
                           President and Chief Operating Officer of the Service
                             Corporation                                         1992-1993
                           Chairman of the Board, President and Chief Executive
                             Officer of Gulf States Utilities Company            1987-1992

Peter J. DeMaria     61    Director                                              1978-Present
                           Vice President                                        1991-Present
                           Controller                                            1995-Present
                           Treasurer                                             1978-1995
                           Controller of AEP                                     1995-Present
                           Treasurer of AEP                                      1978-1995
                           Executive Vice President-Administration and Chief
                             Accounting Officer of the Service Corporation       1984-Present
                           Treasurer of the Service Corporation                  1989-1990

William J. Lhota     56    Director                                              1989-Present
                           President and Chief Operating Officer                 1996-Present
                           Vice President                                        1989-1995
                           Executive Vice President of the Service Corporation   1993-Present
                           Executive Vice President-Operations of the Service
                             Corporation                                         1989-1993

Gerald P. Maloney    63    Director                                              1973-Present
                           Vice President                                        1970-Present
                           Vice President of AEP                                 1974-Present
                           Secretary of AEP                                      1994-Present
                           Executive Vice President-Chief Financial Officer of
                             the Service Corporation                             1991-Present
                           Senior Vice President-Finance of the Service
                             Corporation                                         1974-1990

James J. Markowsky   51    Director                                              1989-Present
                           Vice President                                        1995-Present
                           Executive Vice President-Power Generation of the
                             Service Corporation                                 1996-Present
                           Executive Vice President-Engineering and Construction
                             of the Service Corporation                          1993-1996
                         Senior Vice President and Chief Engineer of the
                            Service Corporation                                  1988-1993


(a) Positions are with OPCo unless otherwise indicated.
<PAGE>
PART II

Item 5.MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

  AEP.  AEP Common Stock is traded principally on the New York Stock Exchange.
The following table sets forth for the calendar periods indicated the high and
low sales prices for the Common Stock as reported on the New York Stock
Exchange Compsite Tape and the amount of cash dividends paid per share of
Common Stock.

     At December 31, 1995, AEP had approximately 170,980 shareholders of 
record.


     AEGCO, APCO, CSPCO, I&M, KEPCO AND OPCO.  The information required by 
this item is not applicable as the common stock of all these companies is 
held solely by AEP.
                                    PER SHARE
                                  MARKET PRICE
QUARTER ENDED                HIGH     LOW      DIVIDEND(1)
March 1994                  $37-3/8  $29-7/8     $.60
June 1994                    32-7/8   27-1/4      .60
September 1994               31-3/4   28          .60
December 1994                33-5/8   30-1/2      .60
March 1995                   35-3/4   31-1/4      .60
June 1995                    35-3/8   31-1/2      .60
September 1995               36-1/2   33-5/8      .60
December 1995                40-5/8   35-7/8      .60

(1)See Note 5 of the Notes to the Consolidated Financial Statements of
  AEP for information regarding restrictions on payment of dividends.



</TABLE>
Item 6.  SELECTED FINANCIAL DATA


   AEGCO.  Omitted pursuant to Instruction J(2)(a).


   AEP.  The information required by this item is incorporated herein by
reference to the material under SELECTED CONSOLIDATED FINANCIAL DATA in the
AEP 1995 Annual Report (for the fiscal year ended December 31, 1995).


   APCO.  The information required by this item is incorporated herein by
reference to the material under SELECTED CONSOLIDATED FINANCIAL DATA in the
APCo 1995 Annual Report (for the fiscal year ended December 31, 1995).


   CSPCO.  Omitted pursuant to Instruction J(2)(a).

   I&M.  The information required by this item is incorporated herein by
reference to the material under SELECTED CONSOLIDATED FINANCIAL DATA in the
I&M 1995 Annual Report (for the fiscal year ended December 31, 1995).

   KEPCO.  Omitted pursuant to Instruction J(2)(a).

   OPCO.  The information required by this item is incorporated herein by
reference to the material under SELECTED CONSOLIDATED FINANCIAL DATA in the
OPCo 1995 Annual Report (for the fiscal year ended December 31, 1995).



Item 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
      OPERATIONS AND FINANCIAL CONDITION



   AEGCO.  Omitted pursuant to Instruction J(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction J(2)(a) is incorporated herein by reference to the material under
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the AEGCo 1995
Annual Report (for the fiscal year ended December 31, 1995).


   AEP.  The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the AEP 1995 Annual Report
(for the fiscal year ended December 31, 1995).


   APCO.  The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the APCo 1995 Annual Report
(for the fiscal year ended December 31, 1995).


   CSPCO.  Omitted pursuant to Instruction J(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction J(2)(a) is incorporated herein by reference to the material under
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the CSPCo 1995
Annual Report (for the fiscal year ended December 31, 1995).


   I&M.  The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the I&M 1995 Annual Report 
(for the fiscal year ended December 31, 1995).


   KEPCO.  Omitted pursuant to Instruction J(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction J(2)(a) is incorporated herein by reference to the material under
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the KEPCo 1995
Annual Report (for the fiscal year ended December 31, 1995).


   OPCO.  The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the OPCo 1995 Annual Report
(for the fiscal year ended December 31, 1995).


Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



   AEGCO.  The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.


   AEP.  The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.


   APCO.  The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.


   CSPCO.  The information required by this item is incorporated  herein  by
reference  to  the financial  statements and supplementary data described under
Item 14 herein.


   I&M.  The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.


   KEPCO.  The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.


   OPCO.  The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.


Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
      ACCOUNTING AND FINANCIAL DISCLOSURE



   AEGCO, AEP, APCO, CSPCO, I&M, KEPCO AND OPCO.  None.
<PAGE>
PART III


Item 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS




   AEGCO.  Omitted pursuant to Instruction J(2)(c).


   AEP.  The information required by this item is incorporated herein by
reference to the material under NOMINEES FOR DIRECTOR and SHARE OWNERSHIP OF
DIRECTORS AND EXECUTIVE OFFICERS of the definitive proxy statement of AEP,
dated March 9, 1996, for the 1996 annual meeting of shareholders.  Reference
also is made to the information under the caption EXECUTIVE OFFICERS OF THE
REGISTRANTS in Part I of this report.


   APCO.  The information required by this item is incorporated herein by
reference to the material under ELECTION OF DIRECTORS of the definitive
information statement of APCo for the 1996 annual meeting of stockholders, 
to be filed within 120 days after December 31, 1995.  Reference also is made
to the information under the caption EXECUTIVE OFFICERS OF THE REGISTRANTS 
in Part I of this report.


   CSPCO.  Omitted pursuant to Instruction J(2)(c).


   I&M.  The names of the directors and executive officers of I&M, the
positions they hold with I&M, their ages as of March 15, 1996, and a brief
account of their business experience during the past five years appear below.
The directors and executive officers of I&M are elected annually to serve a
one-year term.
<TABLE>
<CAPTION>
NAME                  AGE     POSITION (A)(B)(C)                         PERIOD
<S>                   <C>   <C>                                          <C>
E. Linn Draper, Jr.   54  Director                                      1992-Present
                          Chairman of the Board and Chief Executive 
                            Officer                                     1993-Present
                          Vice President                                1992-1993
                          Chairman of the Board, President and Chief 
                            Executive Officer of AEP and of the Service 
                            Corporation                                 1993-Present
                          President of AEP                              1992-1993
                          President and Chief Operating Officer of the 
                            Service Corporation                         1992-1993
                          Chairman of the Board, President and Chief 
                            Executive Officer of Gulf States Utilities 
                            Company                                     1987-1992

Peter J. DeMaria      61  Director                                      1992-Present
                          Vice President                                1991-Present
                          Controller                                    1995-Present
                          Treasurer                                     1978-1995
                          Controller of AEP                             1995-Present
                          Treasurer of AEP                              1978-1995
                          Executive Vice President-Administration and 
                            Chief Accounting Officer of the Service 
                            Corporation                                 1984-Present
                          Treasurer of the Service Corporation          1989-1990

William N. D'Onofrio  48  Director                                      1984-Present
                          Vice President                                1984-1995
                          Director-Regions of the Service Corporation   1996-Present

William J. Lhota      56  Director                                      1989-Present
                          President and Chief Operating Officer         1996-Present
                          Vice President                                1989-1995
                          Executive Vice President of the Service 
                            Corporation                                 1993-Present
                          Executive Vice President-Operations of the 
                            Service Corporation                         1989-1993

Gerald P. Maloney     63  Director                                      1978-Present
                          Vice President                                1970-Present
                          Vice President of AEP                         1974-Present
                          Secretary of AEP                              1994-Present
                          Executive Vice President-Chief Financial 
                            Officer of the Service Corporation          1991-Present
                          Senior Vice President-Finance of the Service
                            Corporation                                 1974-1990

James J. Markowsky    51  Director                                      1995-Present
                          Vice President                                1993-Present
                          Executive Vice President-Power Generation 
                            of the Service Corporation                  1996-Present
                          Executive Vice President-Engineering & 
                            Construction of the Service Corporation     1993-1996
                          Senior Vice President and Chief Engineer 
                            of the Service Corporation                  1988-1993

A. H. Potter          48  Director                                      1994-Present
                          Transmission and Distribution Director        1987-Present

D. M. Trenary         59  Director                                      1994-Present
                          Indiana Region Manager                        1994-Present
                          Division Manager                              1989-1994

W. E. Walters         48  Director                                      1991-Present
                          Michiana Region Manager                       1994-Present
                          Executive Assistant to President              1987-1994

C. R. Boyle, III      48  Director and Vice President                   1996-Present
                          President and Chief Operating Officer of KEPCo1990-1995

G. A. Clark           44  Director                                      1995-Present
                          Governmental Affairs Manager                  1996-Present
                          General Counsel                               1994-1995
                          General Attorney                              1991-1993

D. B. Synowiec        52  Director                                      1995-Present
                          Plant Manager                                 1990-Present

J. H. Vipperman       55  Director and Vice President                   1996-Present
                          Executive Vice President- Energy Delivery 
                            of the Service Corporation                  1996-Present
                          President and Chief Operating Officer of APCo 1990-1995


(a) Positions are with I&M unless otherwise indicated.
(b) Dr. Draper is a director of VECTRA Technologies, Inc. and Mr. Lhota is a
    director of Huntington Bancshares Incorporated.
(c) Drs. Draper and Markowsky and Messrs. DeMaria, Lhota and Maloney are
    directors of AEGCo, APCo, CSPCo, KEPCo and OPCo.  Dr. Draper and Messrs.
    DeMaria and Maloney are also directors of AEP.  Mr. Vipperman is a director
    of APCo, CSPCo, KEPCo and OPCo.

    KEPCo.  Omitted pursuant to Instruction J(2)(c).

    OPCo.  The information required by this item is incorporated herein by
reference to the material under the heading Election of Directors of the
definitive information statement of OPCo for the 1996 annual meeting of 
shareholders, to be filed within 120 days after December 31, 1995.  
Reference also is made to the information under the caption EXECUTIVE
OFFICERS OF THE REGISTRANTS in Part I of this report.

Item 11. EXECUTIVE COMPENSATION



   AEGCO.  Omitted pursuant to Instruction J(2)(c).


   AEP.  The information required by this item is incorporated herein by
reference to the material under COMPENSATION OF DIRECTORS, EXECUTIVE
COMPENSATION and the performance graph of the definitive proxy statement of
AEP, dated March 9, 1996, for the 1996 annual meeting of shareholders.


   APCO.  The information required by this item is incorporated herein by
reference to the material under EXECUTIVE COMPENSATION of the definitive
information statement of APCo for the 1996 annual meeting of stockholders, to
be filed within 120 days after December 31, 1995.


   CSPCO.  Omitted pursuant to Instruction J(2)(c).


   KEPCO.  Omitted pursuant to Instruction J(2)(c).


   OPCO.  The information required by this item is incorporated herein by
reference to the material under EXECUTIVE COMPENSATION of the definitive
information statement of OPCo for the 1996 annual meeting of shareholders, to
be filed within 120 days after December 31, 1995.


   I&M.  Certain executive officers of I&M are employees of the Service
Corporation.  The  salaries  of  these executive officers are paid by the 
Service Corporation and a portion of their salaries has been allocated and 
charged to I&M.  The following table shows for 1995, 1994 and 1993 the 
compensation earned from all AEP System companies by the chief executive 
officer and four other most highly compensated executive officers (as 
defined by regulations of the SEC) of I&M at December 31, 1995.

   SUMMARY COMPENSATION TABLE

</TABLE>
<TABLE>
<CAPTION>
                                                                                   LONG-TERM
                                                       ANNUAL COMPENSATION       COMPENSATION         All Other
                                                            Salary     Bonus       PAYOUTS            Compensation
          NAME AND PRINCIPAL POSITION               YEAR      ($)      ($)(1)   LTIP PAYOUTS($)(1)       ($)(2)
<S>                                                 <C>     <C>       <C>           <C>                   <C>

E. LINN DRAPER, JR. - chairman of the board,        1995    685,000   236,325     334,851                30,790
 president and chief executive officer of the       1994    620,000   209,436     137,362                29,385
 Company and the Service Corporation; chairman      1993    538,333   148,742                            18,180
 and chief executive officer of other subsidiaries

PETER J. DEMARIA - Controller and director of the   1995    330,000   113,850     143,829                20,050
 Company; executive vice president-administration   1994    305,000   103,029      59,032                18,750
 and chief accounting officer and director of the   1993    280,000    77,364                            17,811
 Service Corporation; vice president, controller
 and director of other subsidiaries

G. P. MALONEY - Vice president, secretary and       1995    330,000   113,850     141,582                20,060
 director of the Company; executive vice president  1994    300,000   101,340      58,094                19,745
 - chief financial officer and director of the      1993    269,000    74,325                            18,000
 Service Corporation; vice president and director
 of other subsidiaries

WILLIAM J. LHOTA - Executive vice president and     1995    300,000   103,500     132,592                19,140
 director of the Service Corporation; president,    1994    280,000    94,584      54,409                19,185
 chief operating officer and director of other      1993    249,000    68,799      17,160
 subsidiaries

JAMES J. MARKOWSKY - Executive vice president       1995    285,000    98,325     126,599                17,515
 - power generation and director of the Service     1994    267,000    90,193      51,930                14,755
 Corporation; vice president and director of        1993    247,000    65,259                            11,165
 other subsidiaries



(1)Amounts in the "Bonus" column reflect payments under the Management
   Incentive Compensation Plan for performance measured for each of the years
   ended December 31, 1993, 1994 and 1995.  Payments are made in March of the
   subsequent year.  Amounts for 1995 are estimates but should not change
   significantly.

   Amounts in the "Long-Term Compensation" column reflect performance share
   units earned under the Performance Share Incentive Plan (which became
   effective January 1, 1994) for the one-year and two-year transition
   performance periods ending December 31, 1994 and 1995, respectively.  For
   1995, their value was calculated by multiplying the $40.50 closing price of
   AEP's Common Stock as reported on the New York Stock Exchange on December
   29, 1995, the last trading day of fiscal year 1995, by the number of units
   earned.

   See below under "Long-Term Incentive Plans - Awards in 1995" and pages 13
   and 14 for additional information.

(2)For 1995, includes (i) employer matching contributions under the AEP System
   Employees Savings Plan: $4,500 for each of the named executive officers;
   (ii) employer matching contributions under the AEP System Supplemental
   Savings Plan (which became effective January 1, 1994), a non-qualified plan
   designed to supplement the AEP Savings Plan: Dr. Draper, $16,050;
   Mr. DeMaria, $5,400; Mr. Maloney, $5,400; Mr. Lhota, $4,500; and
   Dr. Markowsky, $4,050; and (iii) subsidiary companies director fees:
   Dr. Draper, $10,240; Mr. DeMaria, $10,150; Mr. Maloney, $10,160; Mr. Lhota,
   $10,140; and Dr. Markowsky, $8,965.


LONG-TERM INCENTIVE PLANS - AWARDS IN 1995


   Each of the awards set forth below constitutes a grant of performance share
units, which represent units equivalent to shares of Common Stock, pursuant to
the Company's Performance Share Incentive Plan.  Since it is not possible to
predict future dividends and the price of AEP Common Stock, credits of
performance share units in amounts equal to the dividends that would have been
paid if the performance share units were granted in the form of shares of
Common Stock are not included in the table.


   The ability to earn performance share units is tied to achieving specified
levels of total shareholder return ("TSR") relative to the S&P Electric Utility
Index.  Notwithstanding AEP's TSR ranking, no performance share units are
earned unless AEP shareholders realize a positive TSR over the relevant
three-year performance period.  The Human Resources Committee may, at its
discretion, reduce the number of performance share units otherwise earned.  
In accordance with the performance goals established for the periods set 
forth below, the threshold, target and maximum awards are equal to 25%, 
100% and 200%, respectively, of the performance share units held.  No 
payment will be made for performance below the threshold.


   Payments of earned awards are deferred in the form of restricted stock units
(equivalent to shares of AEP Common Stock) until the officer has met the
equivalent stock ownership target discussed in the Human Resources Committee
Report.  Once officers meet and maintain their respective targets, they may
elect either to continue to defer or to receive further earned awards in cash
and/or Common Stock.


</TABLE>
<TABLE>
<CAPTION>
                                                         ESTIMATED FUTURE PAYOUTS OF
                                      PERFORMANCE      PERFORMANCE SHARE UNITS UNDER
                       NUMBER OF      PERIOD UNTIL       NON-STOCK PRICE-BASED PLAN
                       Performance     Maturation       Threshold  Target    Maximum
  NAME                 SHARE UNITS     OR PAYOUT           (#)       (#)       (#)
<S>                       <C>         <C>                <C>        <C>      <C>           
E. L. Draper, Jr.         8,302       1995-1997          2,075      8,302    16,604

P. J. DeMaria             3,499       1995-1997            875      3,499    6,998

G. P. Maloney             3,499       1995-1997            875      3,499    6,998

W. J. Lhota               3,181       1995-1997            795      3,181    6,362

J. J. Markowsky           3,022       1995-1997            755      3,022    6,044

</TABLE>
   RETIREMENT BENEFITS

   The American Electric Power System Retirement Plan provides pensions for all
employees of AEP System companies (except for employees covered by certain
collective bargaining agreements), including the executive officers of the
Company.  The Retirement Plan is a noncontributory defined benefit plan.

   The following table shows the approximate annual annuities under the
Retirement Plan that would be payable to employees in certain higher salary
classifications, assuming retirement at age 65 after various periods of
service.

   PENSION PLAN TABLE
<TABLE>
<CAPTION>
HIGHEST AVERAGE                               YEARS OF ACCREDITED SERVICE
ANNUAL EARNINGS      15         20         25         30         35         40         45
<S>              <C>        <C>        <C>        <C>        <C>        <C>        <C>
$  300,000       $ 69,930   $ 93,240   $116,550   $139,860   $163,170   $183,120   $203,070

   400,000         93,930    125,240    156,550    187,860    219,170    245,770    272,370

   500,000        117,930    157,240    196,550    235,860    275,170    308,420    341,670

   700,000        165,930    221,240    276,550    331,860    387,170    433,720    480,270

   900,000        213,930    285,240    356,550    427,860    499,170    559,020    618,870

 1,100,000        261,930    349,240    436,550    523,860    611,170    684,320    757,470

</TABLE>
   The amounts shown in the table are the straight life annuities payable under
the Retirement Plan without reduction for the joint and survivor annuity.
Retirement benefits listed in the table are not subject to any deduction for
Social Security or other offset amounts.  The retirement annuity is reduced 3%
per year in the case of retirement between ages 60 and 62 and further reduced
6% per year in the case of retirement between ages 55 and 60.  If an employee
retires after age 62, there is no reduction in the retirement annuity.


   The Company maintains a supplemental retirement plan which provides for the
payment of benefits that are not payable under the Retirement Plan due
primarily to limitations imposed by Federal tax law on benefits paid by
qualified plans.  The table includes supplemental retirement benefits.


   Compensation upon which retirement benefits are based, for the executive
officers named in the Summary Compensation Table above, consists of the average
of the 36 consecutive months of the officer's highest aggregate salary and
Management Incentive Compensation Plan awards, shown in the "Salary" and
"Bonus" columns, respectively, of the Summary Compensation Table, out of the
officer's most recent 10 years of service.  As of December 31, 1995, the number
of full years of service applicable for retirement benefit calculation purposes
for such officers were as follows:  Dr. Draper, three years; Mr. DeMaria,
36 years; Mr. Maloney, 40 years; Mr. Lhota, 31 years; and Dr. Markowsky,
24 years.


   Dr. Draper's employment agreement described below provides him with a
supplemental retirement annuity that credits him with 24 years of service in
addition to his years of service credited under the Retirement Plan less his
actual pension entitlement under the Retirement Plan and any pension
entitlement from the Gulf States Utilities Company Trusteed Retirement Plan, a
plan sponsored by his prior employer.


   The Company will pay supplemental retirement benefits to 19 AEP System
employees (including Messrs. DeMaria, Maloney and Lhota and Dr. Markowsky)
whose pensions may be adversely affected by amendments to the Retirement Plan
made as a result of the Tax Reform Act of 1986.  Such payments, if any, will be
equal to any reduction occurring because of such amendments.  Assuming 
retirement in 1996 of the executive officers named in the Summary 
Compensation Table, only Mr. Maloney would be affected and his annual 
supplemental benefit would be $972.


   The Company made available a voluntary deferred-compensation program in 1982
and 1986, which permitted certain members of AEP System management to defer
receipt of a portion of their salaries.  Under this program, a participant was
able to defer up to 10% or 15% annually (depending on the terms of the program
offered), over a four-year period, of his or her salary, and receive
supplemental retirement or survivor benefit payments over a 15-year period.
The amount of supplemental retirement payments received is dependent upon the
amount deferred, age at the time the deferral election was made, and number of
years until the participant retires.  The following table sets forth, for the
executive officers named in the Summary Compensation Table, the amounts of
annual deferrals and, assuming retirement at age 65, annual supplemental
retirement payments under the 1982 and 1986 programs.

<TABLE>
<CAPTION>
                                  1982 PROGRAM                         1986 PROGRAM
                                            Annual Amount of                       Annual Amount of
                            Annual          Supplemental         Annual            Supplemental
                            Amount          Retirement           Amount            Retirement
                            Deferred         Payment             Deferred          Payment
NAME                       (4-YEAR PERIOD)  (15-YEAR PERIOD)     (4-YEAR PERIOD)   (15-YEAR PERIOD)

<S>                         <C>              <C>                 <C>               <C>   
P. J. DeMaria               $10,000          $52,000             $13,000           $53,300
G. P. Maloney                15,000           67,500              16,000            56,400

</TABLE>


   EMPLOYMENT AGREEMENT


   Dr. Draper has a contract with the Company and AEP Service Corporation which
provides for his employment for an initial term from no later than March 15,
1992 until March 15, 1997.  Dr. Draper commenced his employment with the
Company and AEP Service Corporation on March 1, 1992.  The Company or AEP
Service Corporation may terminate the contract at any time and, if this is done
for reasons other than cause and other than as a result of Dr. Draper's death
or permanent disability, AEP Service Corporation must pay Dr. Draper's then
base salary through March 15, 1997, less any amounts received by Dr. Draper
from other employment.


   Directors of I&M receive a fee of $100 for each meeting of the Board of
Directors attended in addition to their salaries.


   The AEP System is an integrated electric utility system and, as a result,
the member companies of the AEP System have contractual, financial and other
business relationships with the other member companies, such as participation
in the AEP System savings and retirement plans and tax returns, sales of
electricity, transportation and handling of fuel, sales or rentals of property
and interest or dividend payments on the securities held by the companies'
respective parents.
<PAGE>

Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT


   AEGCO.  Omitted pursuant to Instruction J(2)(c).


   AEP.  The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers of the definitive proxy statement of AEP, dated March 9, 1996, for 
the 1996 annual meeting of shareholders.


   APCO.  The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information statement of APCo for the 1995 annual
meeting of stockholders, to be filed within 120 days after December 31, 1995.


   CSPCO.  Omitted pursuant to Instruction J(2)(c).


   I&M.  All 1,400,000 outstanding shares of Common Stock, no par value, of 
I&M are directly and beneficially held by AEP.  Holders of the Cumulative 
Preferred Stock of I&M generally have no voting rights, except with respect 
to certain corporate actions and in the event of certain defaults in the 
payment of dividends on such shares.


   The table below shows the number of shares of AEP Common Stock and stock-
based units that were beneficially owned, directly or indirectly, as of January
1, 1996, by each director and nominee of I&M and each of the executive officers
of I&M named in the summary compensation table, and by all directors and
executive officers of I&M as a group.  It is based on information provided to
I&M by such persons.  No such person owns any shares of any series of the
Cumulative Preferred Stock of I&M.  Unless otherwise noted, each person has
sole voting power and investment power over the number of shares of AEP Common
Stock and stock-based units set forth opposite his name.  Fractions of shares
and units have been rounded to the nearest whole number.

<TABLE>
<CAPTION>
                                                          STOCK
         NAME                       SHARES                UNITS(a)      TOTAL
<S>                                 <C>                   <C>           <C>
Coulter R. Boyle, III               3,470(b)                 629        4,099
Gregory A. Clark                      833(b)                 327        1,160
Peter J. DeMaria                    7,356(b)(c)(d)(e)(f)   5,391       12,747
William N. D'Onofrio                4,154(b)(e)              492        4,646
E. Linn Draper, Jr.                 6,119(b)(e)           11,984       18,103
William J. Lhota                   13,064(b)(d)(e)         4,944       18,008
Gerald P. Maloney                   5,227(b)(d)(e)         5,306       10,533
James J. Markowsky                  6,631(b)(f)            4,714       11,345
Albert H. Potter                    3,084(b)(e)                -        3,084
David B. Synowiec                   2,214(b)                 398        2,612
Dale M. Trenary                        64(b)                 412          476
Joseph H. Vipperman                 5,092(b)(e)            3,365        8,457
William E. Walters                  4,738(b)                 278        5,016
All Directors and Executive 
  Officers                        147,277(d)(g)           38,240      185,517


</TABLE>
(a)This column includes amounts deferred in stock units and held under the
   Management Incentive Compensation Plan and Performance Share Incentive Plan.
(b)Includes shares and share equivalents held in the following plans in the
   amounts listed below:

<TABLE>
<CAPTION>
                              AEP EMPLOYEE STOCK       AEP PERFORMANCE       AEP EMPLOYEES SAVINGS
                            OWNERSHIP PLAN (SHARES)  SHARE INCENTIVE PLAN  (SHARES)PLAN (SHARE EQUIVALENTS)
<S>                              <C>                     <C>                  <C>
Mr. Boyle                              47                     316                   3,107
Mr. Clark                               8                      -                      825
Mr. DeMaria                            83                     944                   2,705
Mr. D'Onofrio                          59                      -                    3,595
Dr. Draper                              -                   2,196                   1,958
Mr. Lhota                              60                     812                  10,824
Mr. Maloney                            85                     867                   2,775
Dr. Markowsky                          66                     830                   5,718
Mr. Potter                             41                      -                    3,029
Mr. Synowiec                           53                      -                    2,161
Mr. Trenary                            41                      -                       23
Mr. Vipperman                          80                     564                   4,391
Mr. Walters                            45                      -                    4,693
All Directors and Executive Officers  668                   6,529                  45,804
</TABLE>
   With respect to the shares and share equivalents held in these plans, such
   persons have sole voting power, but the investment/disposition power is
   subject to the terms of such plans.
(c)Mr. DeMaria owns 100 shares of Cumulative Preferred Shares 9.50% Series,
   $100 par value, of Columbus Southern Power Company.
(d)Does not include, for Messrs. DeMaria, Lhota and Maloney, 85,231 shares in
   the American Electric Power System Educational Trust Fund over which
   Messrs. DeMaria, Lhota and Maloney share voting and investment power as
   trustees (they disclaim beneficial ownership). The amount of shares shown
   for all directors and executive officers as a group includes these shares.
(e)Includes the following numbers of shares held in joint tenancy with a family
   member: Mr. DeMaria, 1,232; Mr. D'Onofrio, 500; Dr. Draper, 1,965;
   Mr. Lhota, 1,368; Mr. Maloney, 1,500; Mr. Potter, 14; and Mr. Vipperman, 57.
(f)Includes the following numbers of shares held by family members over which
   beneficial ownership is disclaimed:  Mr. DeMaria, 2,392; and Dr. Markowsky,
   17.
(g)Represents less than 1% of the total number of shares outstanding.


   KEPCO.  Omitted pursuant to Instruction J(2)(c).


   OPCO.  The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information statement of OPCo for the 1996 annual
meeting of shareholders, to be filed within 120 days after December 31, 1995.


Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS



   AEP.  The information required by this item is incorporated herein by
reference to the material under Transactions With Management of the definitive
proxy statement of AEP, dated March 9, 1996, for the 1996 annual meeting of
shareholders.

   APCO, I&M AND OPCO.  None.

   AEGCO, CSPCO, AND KEPCO.  Omitted pursuant to Instruction J(2)(c).
<PAGE>

PART IV

Item 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K



(a)The following documents are filed as a part of this report:

1.FINANCIAL STATEMENTS:


  The following financial statements have been incorporated herein by reference
  pursuant to Item 8.


  AEGCo:
     Independent Auditors' Report; Statements of Income for the years ended
       December 31, 1995, 1994 and 1993; Statements of Retained Earnings for
       the years ended December 31, 1995, 1994 and 1993; Statements of Cash
       Flows for the years ended December 31, 1995, 1994 and 1993; Balance
       Sheets as of December 31, 1995 and 1994; Notes to Financial Statements.

  AEP and its subsidiaries consolidated:
     Consolidated Statements of Income for the years ended December 31, 1995,
       1994 and 1993; Consolidated Statements of Retained Earnings for the
       years ended December 31, 1995, 1994 and 1993; Consolidated Statements of
       Cash Flows for the years ended December 31, 1995, 1994 and 1993;
       Consolidated Balance Sheets as of December 31, 1995 and 1994; Notes to
       Consolidated Financial Statements; Schedule of Consolidated Cumulative
       Preferred Stocks of Subsidiaries at December 31, 1995 and 1994; Schedule
       of Consolidated Long-term Debt of Subsidiaries at December 31, 1995 and
       1994; Independent Auditors' Report.

  APCo:
     Independent Auditors' Report; Consolidated Statements of Income for the
       years ended December 31, 1995, 1995 and 1994; Consolidated Balance
       Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
       Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
       Statements of Retained Earnings for the years ended December 31, 1995,
       1994 and 1993; Notes to Consolidated Financial Statements.

  CSPCo:
     Independent Auditors' Report; Consolidated Statements of Income for the
       years ended December 31, 1995, 1994 and 1993; Consolidated Balance
       Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
       Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
       Statements of Retained Earnings for the years ended December 31, 1995,
       1994 and 1993; Notes to Consolidated Financial Statements.

  I&M:
     Independent Auditors' Report; Consolidated Statements of Income for the
       years ended December 31, 1995, 1994 and 1993; Consolidated Balance
       Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
       Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
       Statements of Retained Earnings for the years ended December 31, 1995,
       1994 and 1993; Notes to Consolidated Financial Statements.

  KEPCo:
     Independent Auditors' Report; Statements of Income for the years ended
       December 31, 1995, 1994 and 1993; Statements of Retained Earnings for
       the years ended December 31, 1995, 1994 and 1993; Balance Sheets as of
       December 31, 1995 and 1994; Statements of Cash Flows for the years ended
       December 31, 1995, 1994 and 1993; Notes to Financial Statements.

  OPCo:
     Independent Auditors' Report; Consolidated Statements of Income for the
       years ended December 31, 1995,  1994 and 1993; Consolidated Balance
       Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
       Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
       Statements of Retained Earnings for the years ended December 31, 1995,
       1994 and 1993; Notes to Consolidated Financial Statements.


2.FINANCIAL STATEMENT SCHEDULES:

  Financial Statement Schedules are listed in the Index to Financial 
  Statement Schedules (Certain schedules have been omitted because the
  required information is contained in the notes to financial statements
  or because such schedules are not required or are not applicable.)       S-1

  Independent Auditors' Report                                             S-2

3.EXHIBITS:

  Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo are listed 
  in the Exhibit Index and are incorporated herein by reference            E-1

(b) No Reports on Form 8-K were filed during the quarter ended December 31,
1995.
<PAGE>
                                  SIGNATURES


    PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.  THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.

                                          AEP GENERATING COMPANY


                                             BY:  /S/  G. P. MALONEY
                                                (G. P. MALONEY, VICE
                                                   PRESIDENT)

Date:  March 25, 1996

    PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.  THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.

<TABLE>
<CAPTION>
                   SIGNATURE                 TITLE                   DATE

<S>                                  <C>                             <C>
  (i) Principal Executive Officer:


        *E. LINN DRAPER, JR.               President,
                                     Chief Executive Officer
                                          and Director



  (II) PRINCIPAL FINANCIAL OFFICER:


           /S/ G. P. MALONEY            Vice President         March 25, 1996
           (G. P. MALONEY)                and Director

 (III) PRINCIPAL ACCOUNTING OFFICER:


           /S/ P. J. DEMARIA            Vice President, 
           (P. J. DEMARIA)                Controller           March 25, 1996
                                         and Director

  (IV) A MAJORITY OF THE DIRECTORS:


            *HENRY FAYNE

         *JOHN R. JONES, III

            *WM. J. LHOTA

         *JAMES J. MARKOWSKY


*By:           /S/ G. P. MALONEY                             March 25, 1996
  (G. P. MALONEY, ATTORNEY-IN-FACT)

</TABLE>
<PAGE>
                                  SIGNATURES


    PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.

                                          AMERICAN ELECTRIC POWER COMPANY, INC.


                                             BY:           /S/  G. P. MALONEY
                                                      (G. P. MALONEY, VICE
                                                PRESIDENT)

Date:  March 25, 1996

    PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.

<TABLE>
<CAPTION>
          SIGNATURE                         TITLE                   DATE
<S>                                     <C>                      <C>

  (i) Principal Executive Officer:


        *E. LINN DRAPER, JR.         Chairman of the Board,
                                           President,
                                     Chief Executive Officer
                                          and Director



  (II) PRINCIPAL FINANCIAL OFFICER:


           /S/ G. P. MALONEY              Vice President,      March 25, 1996
           (G. P. MALONEY)                Secretary and 
                                             Director

 (III) PRINCIPAL ACCOUNTING OFFICER:


          /S/ P. J. DEMAA              Controller and Director March 25, 1996
           (P. J. DEMARIA)

  (IV) A MAJORITY OF THE DIRECTORS:


          *ROBERT M. DUNCAN

           *ROBERT W. FRI

          *ARTHUR G. HANSEN

       *LESTER A. HUDSON, JR.

          *ANGUS E. PEYTON

            *TOY F. REID

          *DONALD G. SMITH

       *LINDA GILLESPIE STUNTZ

          *MORRIS TANENBAUM

        *ANN HAYMOND ZWINGER


*By:        /S/ G. P. MALONEY                                  March 25, 1996
  (G. P. MALONEY, ATTORNEY-IN-FACT)

</TABLE>
<PAGE>

                                  SIGNATURES


    PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.  THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.

                                          APPALACHIAN POWER COMPANY


                                             BY:    /S/  G. P. MALONEY
                                                  (G. P. MALONEY, VICE
                                                      PRESIDENT)

Date:  March 25, 1996

    PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.  THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.

<TABLE>
<CAPTION>
         SIGNATURE                          TITLE                   DATE
<S>                                    <C>                       <C>

  (i) Principal Executive Officer:


        *E. LINN DRAPER, JR.         Chairman of the Board,
                                     Chief Executive Officer
                                          and Director



  (II) PRINCIPAL FINANCIAL OFFICER:


          /S/ G. P. MALONEY              Vice President        March 25, 1996
          (G. P. MALONEY)                and Director

 (III) PRINCIPAL ACCOUNTING OFFICER:

         /S/ P. J. DEMARIA              Vice President,        March 25, 1996
           (P. J. DEMARIA)                Controller 
                                         and Director

  (IV) A MAJORITY OF THE DIRECTORS:


            *HENRY FAYNE

            *WM. J. LHOTA

         *JAMES J. MARKOWSKY

          *J. H. VIPPERMAN


*By:           /S/ G. P. MALONEY                               March 25, 1996
  (G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
                                  SIGNATURES


    PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.  THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.

                                          COLUMBUS SOUTHERN POWER COMPANY


                                             BY:    /S/  G. P. MALONEY
                                                (G. P. MALONEY, VICE
                                                      PRESIDENT)

Date:  March 25, 1996

    PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.  THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.

<TABLE>
<CAPTION>
             SIGNATURE                      TITLE                   DATE

<S>                                   <C>                         <C>
  (i) Principal Executive Officer:


        *E. LINN DRAPER, JR.         Chairman of the Board,
                                     Chief Executive Officer
                                          and Director



  (II) PRINCIPAL FINANCIAL OFFICER:


          /S/ G. P. MALONEY              Vice President        March 25, 1996
           (G. P. MALONEY)                and Director

 (III) PRINCIPAL ACCOUNTING OFFICER:


         /S/ P. J. DEMARIA              Vice President, ControllerMarch 25, 1996
           (P. J. DEMARIA)                Controller 
                                         and Director

  (IV) A MAJORITY OF THE DIRECTORS:


            *HENRY FAYNE

            *WM. J. LHOTA

         *JAMES J. MARKOWSKY

          *J. H. VIPPERMAN


*By:    /S/ G. P. MALONEY                                      March 25, 1996
  (G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
                                  SIGNATURES


    PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.  THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.

                                          INDIANA MICHIGAN POWER COMPANY


                                             BY:   /S/  G. P. MALONEY
                                                (G. P. MALONEY, VICE
                                                      PRESIDENT)

Date:  March 25, 1996

    PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.  THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.

<TABLE>
<CAPTION>
     SIGNATURE                            TITLE                   DATE
<S>                                   <C>                         <C>           

  (i) Principal Executive Officer:


        *E. LINN DRAPER, JR.         Chairman of the Board,
                                     Chief Executive Officer
                                          and Director



  (II) PRINCIPAL FINANCIAL OFFICER:


          /S/ G. P. MALONEY              Vice President        March 25, 1996
           (G. P. MALONEY)                and Director


 (III) PRINCIPAL ACCOUNTING OFFICER:


         /S/ P. J. DEMARIA              Vice President,        March 25, 1996
           (P. J. DEMARIA)                Controller
                                          and Director

  (IV) A MAJORITY OF THE DIRECTORS:


          *C. R. BOYLE, III

            *G. A. CLARK

          *W. N. D'ONOFRIO

            *WM. J. LHOTA

         *JAMES J. MARKOWSKY

            *A. H. POTTER

           *D. B. SYNOWIEC

           *D. M. TRENARY

          *J. H. VIPPERMAN

           *W. E. WALTERS


*By:    /S/ G. P. MALONEY                                      March 25, 1996
  (G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
                                  SIGNATURES


    PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.  THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.

                                          KENTUCKY POWER COMPANY


                                             BY:   /S/  G. P. MALONEY
                                                (G. P. MALONEY, VICE
                                                     PRESIDENT)

Date:  March 25, 1996

    PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.  THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.

<TABLE>
<CAPTION>
          SIGNATURE                        TITLE                   DATE

<S>                                    <C>                     <C>
  (i) Principal Executive Officer:


        *E. LINN DRAPER, JR.         Chairman of the Board,
                                     Chief Executive Officer
                                          and Director



  (II) PRINCIPAL FINANCIAL OFFICER:


          /S/ G. P. MALONEY              Vice President        March 25, 1996
           (G. P. MALONEY)                and Director

 (III) PRINCIPAL ACCOUNTING OFFICER:


          /S/ P. J. DEMARIA              Vice President,       March 25, 1996
           (P. J. DEMARIA)                Controller 
                                          and Director

  (IV) A MAJORITY OF THE DIRECTORS:


            *WM. J. LHOTA

         *JAMES J. MARKOWSKY

          *J. H. VIPPERMAN


*By:    /S/ G. P. MALONEY                                      March 25, 1996
  (G. P. MALONEY, ATTORNEY-IN-FACT)

</TABLE>
<PAGE>
                                  SIGNATURES


    PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.  THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.

                                          OHIO POWER COMPANY


                                             BY:           /S/  G. P. MALONEY
                                                      (G. P. MALONEY, VICE
                                                PRESIDENT)

Date:  March 25, 1996

    PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.  THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.

<TABLE>
<CAPTION>
             SIGNATURE                      TITLE                   DATE
<S>                                   <C>                       <C>
  (i) Principal Executive Officer:

        *E. LINN DRAPER, JR.         Chairman of the Board,
                                     Chief Executive Officer
                                          and Director


  (II) PRINCIPAL FINANCIAL OFFICER:


         /S/ G. P. MALONEY              Vice President         March 25, 1996
         (G. P. MALONEY)                and Director

 (III) PRINCIPAL ACCOUNTING OFFICER:


         /S/ P. J. DEMARIA              Vice President,        March 25, 1996
           (P. J. DEMARIA)                Controller
                                         and Director

  (IV) A MAJORITY OF THE DIRECTORS:


            *HENRY FAYNE

            *WM. J. LHOTA

         *JAMES J. MARKOWSKY

          *J. H. VIPPERMAN


*By:    /S/ G. P. MALONEY                                      March 25, 1996
  (G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
                    INDEX TO FINANCIAL STATEMENT SCHEDULES


                                                                       PAGE

INDEPENDENT AUDITORS' REPORT                                            S-2

The following financial statement schedules for the years ended 
December 31, 1995, 1994 and 1993 are included in this report on 
the pages indicated.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

   Schedule II-   Valuation and Qualifying Accounts and Reserves        S-3

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

   Schedule II-   Valuation and Qualifying Accounts and Reserves        S-3

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

   Schedule II-   Valuation and Qualifying Accounts and Reserves        S-3

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

   Schedule II-   Valuation and Qualifying Accounts and Reserves        S-4

KENTUCKY POWER COMPANY

   Schedule II-   Valuation and Qualifying Accounts and Reserves        S-4

OHIO POWER COMPANY AND SUBSIDIARIES

   Schedule II-   Valuation and Qualifying Accounts and Reserves        S-4
<PAGE>
                         INDEPENDENT AUDITORS' REPORT


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES:

   We have audited the consolidated financial statements of American Electric
Power Company, Inc. and its subsidiaries and the financial statements of
certain of its subsidiaries, listed in Item 14 herein, as of December 31, 1995
and 1994, and for each of the three years in the period ended December 31,
1995, and have issued our reports thereon dated February 27, 1996; such
financial statements and reports are included in your respective 1995 Annual
Report and are incorporated herein by reference.  Our audits also included the
financial statement schedules of American Electric Power Company, Inc. and its
subsidiaries and of certain of its subsidiaries, listed in Item 14.  These
financial statement schedules are the responsibility of the respective
Company's management.  Our responsibility is to express an opinion based on our
audits.  In our opinion, such financial statement schedules, when considered in
relation to the corresponding basic financial statements taken as a whole,
present fairly in all material respects the information set forth therein.




DELOITTE & TOUCHE LLP
Columbus, Ohio
February 27, 1996
<PAGE>
<TABLE>
<CAPTION>
        AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
         SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

             COLUMN A               COLUMN B           COLUMN C          COLUMN D     COLUMN E


                                                       ADDITIONS
                                    Balance at  Charged to  Charged to                Balance at
                                    Beginning   Costs and   Other                     End of
              Description           of Period   Expenses    Accounts     Deductions   Period
<S>                                 <C>         <C>         <C>          <C>          <C>
                                                   (in thousands)

Deducted from Assets:
  Accumulated Provision for
    Uncollectible Accounts:
     Year Ended December 31, 1995   $4,056      $12,907     $ 5,927(a)   $17,460(b)   $5,430

     Year Ended December 31, 1994   $4,048      $20,265     $(3,556)(a)  $16,701(b)   $4,056

     Year Ended December 31, 1993   $7,287      $14,237     $ 4,163(a)   $21,639(b)   $4,048
</TABLE>

(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.


<TABLE>
<CAPTION>
                  APPALACHIAN POWER COMPANY AND SUBSIDIARIES
         SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

              COLUMN A                  COLUMN B          COLUMN C            COLUMN D    COLUMN E

                                                          ADDITIONS
                                       Balance at   Charged to   Charged to               Balance at
                                       Beginning    Costs and    Other                    End of
              Description              of Period    Expenses     Accounts    Deductions   Period
<S>                                   <C>           <C>          <C>         <C>          <C>
                                                (in thousands)
Deducted from Assets:
  Accumulated Provision for
    Uncollectible Accounts:
     Year Ended December 31, 1995     $ 830         $ 3,442      $   963 (a) $ 2,982(b)   $2,253

     Year Ended December 31, 1994     $1,344        $ 2,297      $   596 (a) $ 3,407(b)   $ 830

     Year Ended December 31, 1993     $ 724         $ 3,392      $   627 (a) $ 3,399(b)   $1,344


</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.

               COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
         SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES


<TABLE>
<CAPTION>
           COLUMN A                 COLUMN B            COLUMN C        COLUMN D    COLUMN E


                                                       ADDITIONS
                                    Balance at  Charged to  Charged to              Balance at
                                    Beginning   Costs and   Other                   End of
              Description           of Period   Expenses    Accounts    Deductions  Period
<S>                                 <C>         <C>         <C>         <C>         <C>

                                                (in thousands)
Deducted from Assets:
  Accumulated Provision for
    Uncollectible Accounts:
     Year Ended December 31, 1995   $1,768      $ 4,873     $ 3,531(a)  $ 9,111(b)  $1,061

     Year Ended December 31, 1994   $ 991       $ 6,181     $ 2,778(a)  $ 8,182(b)  $1,768

     Year Ended December 31, 1993   $1,332      $ 4,167     $ 2,106(a)  $ 6,614(b)  $  991


</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<PAGE>
                INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
         SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<TABLE>
<CAPTION>
              COLUMN A                    COLUMN B           COLUMN C          COLUMN D    COLUMN E
                                                             ADDITIONS
                                          Balance at  Charged to  Charged to               Balance at
                                          Beginning   Costs and   Other                    End of
              Description                 of Period   Expenses    Accounts    Deductions   Period
<S>                                       <C>         <C>         <C>         <C>          <C>
                                                (in thousands)

Deducted from Assets:
  Accumulated Provision for
    Uncollectible Accounts:
     Year Ended December 31, 1995         $  121      $ 1,506     $   632(a)   $ 1,925(b)   $  334

     Year Ended December 31, 1994         $  504      $  774      $   707(a)   $ 1,864(b)   $  121

     Year Ended December 31, 1993         $  562      $ 1,380     $   624(a)   $ 2,062(b)   $  504

</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.

<TABLE>
<CAPTION>

                            KENTUCKY POWER COMPANY
         SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

         COLUMN A                    COLUMN B          COLUMN C           COLUMN D     COLUMN E
                                                       ADDITIONS
                                     Balance at  Charged to  Charged to                Balance at
                                     Beginning   Costs and   Other                     End of
       Description                   of Period   Expenses    Accounts     Deductions   Period
<S>                                  <C>         <C>         <C>          <C>          <C>
                                                      (in thousands)
Deducted from Assets:
  Accumulated Provision for
    Uncollectible Accounts:
     Year Ended December 31, 1995    $  260      $   925     $   234(a)   $ 1,160(b)   $  259

     Year Ended December 31, 1994    $  208      $   600     $    84(a)   $  632(b)    $  260

     Year Ended December 31, 1993    $  248      $   390     $   179(a)   $  609(b)    $  208

</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.

                      OHIO POWER COMPANY AND SUBSIDIARIES
         SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<TABLE>
<CAPTION>
              COLUMN A                       COLUMN B          COLUMN C             COLUMN D   COLUMN E
                                                               ADDITIONS
                                            Balance at   Charged to  Charged to                Balance at
                                            Beginning    Costs and   Other                     End of
              Description                   of Period    Expenses    Accounts     Deductions   Period
<S>                                         <C>          <C>         <C>          <C>          <C>
                                                (in thousands)
Deducted from Assets:
  Accumulated Provision for
    Uncollectible Accounts:
     Year Ended December 31, 1995    $1,019       $ 1,952     $   472(a)    $ 2,019(b)   $1,424

     Year Ended December 31, 1994    $ 960        $10,087     $(7,785)(a)   $ 2,243(b)   $1,019

     Year Ended December 31, 1993    $4,353       $ 4,812     $   549(a)    $ 8,754(b)   $960


</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.

<PAGE>
                                  EXHIBIT INDEX

    Certain of the following exhibits, designated with an asterisk(*), are
filed herewith.  The exhibits not so designated have heretofore been filed with
the Commission and, pursuant to 17 C.F.R. <section>229.10(d) and
<section>240.12b-32, are incorporated herein by reference to the documents
indicated in brackets following the descriptions of such exhibits.  Exhibits,
designated with a dagger (<dagger>), are management contracts or compensatory
plans or arrangements required to be filed as an exhibit to this form pursuant
to Item 14(c) of this report.


EXHIBIT NUMBER                                       DESCRIPTION

AEGCO

   3(a)    - Copy of Articles of Incorporation of AEGCo [Registration Statement
             on Form 10 for the Common Shares of AEGCo, File No. 0-18135,
             Exhibit 3(a)].
   3(b)    - Copy of the Code of Regulations of AEGCo [Registration Statement
             on Form 10 for the Common Shares of AEGCo, File No. 0-18135,
             Exhibit 3(b)].
  10(a)    - Copy of Capital Funds Agreement dated as of December 30, 1988
             between AEGCo and AEP [Registration Statement No. 33-32752,
             Exhibit 28(a)].
  10(b)(1) - Copy of Unit Power Agreement dated as of March 31, 1982 between
             AEGCo and I&M, as amended [Registration Statement No. 33-32752,
             Exhibits 28(b)(1)(A) and 28(b)(1)(B)].
  10(b)(2) - Copy of Unit Power Agreement, dated as of August 1, 1984, among
             AEGCo, I&M and KEPCo [Registration Statement No. 33-32752, Exhibit
             28(b)(2)].
  10(b)(3) - Copy of Agreement, dated as of October 1, 1984, among AEGCo, I&M,
             APCo and Virginia Electric and Power Company [Registration
             Statement No. 33-32752, Exhibit 28(b)(3)].
  10(c)    - Copy of Lease Agreements, dated as of December 1, 1989, between
             AEGCo and Wilmington Trust Company, as amended [Registration
             Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C),
             28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Annual
             Report on Form 10-K of AEGCo for the fiscal year ended December
             31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B),
             10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B)].
 *13       - Copy of those portions of the AEGCo 1995 Annual Report (for the
             fiscal year ended December 31, 1995) which are incorporated by
             reference in this filing.
 *24       - Power of Attorney.
 *27       - Financial Data Schedules.


AEP<double-dagger>

   3(a)    - Copy of Restated Certificate of Incorporation of AEP, dated April
             26, 1978 [Registration Statement No. 2-62778, Exhibit 2(a)].
   3(b)(1) - Copy of Certificate of Amendment of the Restated Certificate of
             Incorporation of AEP, dated April 23, 1980 [Registration Statement
             No. 33-1052, Exhibit 4(b)].
   3(b)(2) - Copy of Certificate of Amendment of the Restated Certificate of
             Incorporation of AEP, dated April 28, 1982 [Registration Statement
             No. 33-1052, Exhibit 4(c)].
   3(b)(3) - Copy of Certificate of Amendment of the Restated Certificate of
             Incorporation of AEP, dated April 25, 1984 [Registration Statement
             No. 33-1052, Exhibit 4(d)].
   3(b)(4) - Copy of Certificate of Change of the Restated Certificate of
             Incorporation of AEP, dated July 5, 1984 [Registration Statement
             No. 33-1052, Exhibit 4(e)].
   3(b)(5) - Copy of Certificate of Amendment of the Restated Certificate of
             Incorporation of AEP, dated April 27, 1988 [Registration Statement
             No. 33-1052, Exhibit 4(f)].
   3(c)    - Composite copy of the Restated Certificate of Incorporation of
             AEP, as amended [Registration Statement No. 33-1052, Exhibit
             4(g)].
   3(d)    - Copy of By-Laws of AEP, as amended through July 26, 1989 [Annual
             Report on Form 10-K of AEP for the fiscal year ended December 31,
             1989, File No. 1-3525, Exhibit 3(d)].
  10(a)    - Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo,
             KEPCo, OPCo and I&M and with the Service Corporation, as amended
             [Registration Statement No. 2-52910, Exhibit 5(a); Registration
             Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-
             K of AEP for the fiscal year ended December 31, 1990, File No. 1-
             3525, Exhibit 10(a)(3)].
  10(b)    - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
             CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent,
             as amended [Annual Report on Form 10-K of AEP for the fiscal year
             ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and
             Annual Report on Form 10-K of AEP for the fiscal year ended
             December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].

AEP<double-dagger> (continued)

EXHIBIT NUMBER                                       DESCRIPTION

 <dagger>10(c)(1)-AEP Deferred Compensation Agreement for certain executive
             officers [Annual Report on Form 10-K of AEP for the fiscal year
             ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].
 <dagger>10(c)(2)-Amendment to AEP Deferred Compensation Agreement for certain
             executive officers [Annual Report on Form 10-K of AEP for the
             fiscal year ended December 31, 1986, File No. 1-3525, Exhibit
             10(d)(2)].
 <dagger>10(d)-AEP Deferred Compensation Agreement for directors, as amended,
             effective October 24, 1984 [Annual Report on Form 10-K of AEP for
             the fiscal year ended December 31, 1984, File No. 1-3525, Exhibit
             10(e)].
 <dagger>10(e)-AEP Accident Coverage Insurance Plan for directors [Annual
             Report on Form 10-K of AEP for the fiscal year ended December 31,
             1985, File No. 1-3525, Exhibit 10(g)].
 <dagger>10(f)-AEP Retirement Plan for directors [Annual Report on Form 10-K of
             AEP for the fiscal year ended December 31, 1986, File No. 1-3525,
             Exhibit 10(g)].
*<dagger>10(g)(1)(A)-AEP Excess Benefit Plan, as amended through January 4,
             1996.
 <dagger>10(g)(1)(B)-Guaranty by AEP of the Service Corporation Excess Benefits
             Plan [Annual Report on Form 10-K of AEP for the fiscal year ended
             December 31, 1990, File No. 1-3525, Exhibit 10(h)(1)(B)].
 <dagger>10(g)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual
             Report on Form 10-K of AEP for the fiscal year ended December 31,
             1993, File No. 1-3525, Exhibit 10(g)(2)].
 <dagger>10(g)(3)-Service Corporation Umbrella Trust<trademark> for Executives
             [Annual Report on Form 10-K of AEP for the fiscal year ended
             December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
 <dagger>10(h)(1)-Employment Agreement between E. Linn Draper, Jr. and AEP and
             the Service Corporation [Annual Report on Form 10-K of AEGCo for
             the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit
             10(g)(3)].
*<dagger>10(i)(1)-AEP Management Incentive Compensation Plan.
 <dagger>10(i)(2)-American Electric Power System Performance Share Incentive
             Plan, as Amended and Restated through October 1, 1995 [Quarterly
             Report on Form 10-Q of AEP for the quarterly period ended
             September 30, 1995, File No. 1-3525, Exhibit 10].
  10(j)    - Copy of Lease Agreements, dated as of December 1, 1989, between
             AEGCo or I&M and Wilmington Trust Company, as amended
             [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C),
             28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and
             28(c)(6)(C); Registration Statement No. 33-32753, Exhibits
             28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C)
             and 28(a)(6)(C); and Annual Report on Form 10-K of AEGCo for the
             fiscal year ended December 31, 1993, File No. 0-18135, Exhibits
             10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B)
             and 10(c)(6)(B); Annual Report on Form 10-K of I&M for the fiscal
             year ended December 31, 1993, File No. 1-3570, Exhibits
             10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B)
             and 10(e)(6)(B)].
  10(k)(1) - Copy of Agreement for Lease, dated as of September 17, 1992,
             between JMG Funding, Limited Partnership and OPCo [Annual Report
             on Form 10-K of OPCo for the fiscal year ended December 31, 1992,
             File No. 1-6543, Exhibit 10(l)].
  10(k)(2) - Lease Agreement between Ohio Power Company and JMG Funding,
             Limited, dated January 20, 1995 [Annual Report on Form 10-K of
             OPCo for the fiscal year ended December 31, 1994, File No. 1-6543,
             Exhibit 10(l)(2)].
  10(l)    - Interim Allowance Agreement, dated July 28, 1994, among APCo,
             CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report
             on Form 10-K of APCo for the fiscal year ended December 31, 1994,
             File No. 1-3457, Exhibit 10(d)].
 *13       - Copy of those portions of the AEP 1995 Annual Report (for the
             fiscal year ended December 31, 1995) which are incorporated by
             reference in this filing.
 *21       - List of subsidiaries of AEP.
 *23       - Consent of Deloitte & Touche LLP.
 *24       - Power of Attorney.
 *27       - Financial Data Schedules.

APCO<double-dagger>

EXHIBIT NUMBER                                       DESCRIPTION

   3(a)    - Copy of Restated Articles of Incorporation of APCo, and amendments
             thereto to November 4, 1993 [Registration Statement No. 33-50163,
             Exhibit 4(a); Registration Statement No. 33-53805, Exhibits 4(b)
             and 4(c)].
   3(b)    - Copy of Articles of Amendment to the Restated Articles of
             Incorporation of APCo, dated June 6, 1994 [Annual Report on Form
             10-K of APCo for the fiscal year ended December 31, 1994, File No.
             1-3457, Exhibit 3(b)].
   3(c)    - Composite copy of the Restated Articles of Incorporation of APCo,
             as amended [Annual Report on Form 10-K of APCo for the fiscal year
             ended December 31, 1994, File No. 1-3457, Exhibit 3(c)].
  *3(d)    - Copy of By-Laws of APCo (amended as of January 1, 1996).
   4(a)    - Copy of Mortgage and Deed of Trust, dated as of December 1, 1940,
             between APCo and Bankers Trust Company and R. Gregory Page, as
             Trustees, as amended and supplemented [Registration Statement No.
             2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit
             2(1); Registration Statement No. 2-24453, Exhibit 2(n);
             Registration Statement No. 2-60015, Exhibits 2(b)(2), 2(b)(3),
             2(b)(4), 2(b)(5), 2(b)(6), 2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10),
             2(b)(12), 2(b)(14), 2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18),
             2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24),
             2(b)(25), 2(b)(26), 2(b)(27) and 2(b)(28); Registration Statement
             No. 2-64102, Exhibit 2(b)(29); Registration Statement No. 2-66457,
             Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No. 2-
             69217, Exhibit 2(b)(32); Registration Statement No. 2-86237,
             Exhibit 4(b); Registration Statement No. 33-11723, Exhibit 4(b);
             Registration Statement No. 33-17003, Exhibit 4(a)(ii),
             Registration Statement No. 33-30964, Exhibit 4(b); Registration
             Statement No. 33-40720, Exhibit 4(b); Registration Statement No.
             33-45219, Exhibit 4(b); Registration Statement No. 33-46128,
             Exhibits 4(b) and 4(c); Registration Statement No. 33-53410,
             Exhibit 4(b); Registration Statement No. 33-59834, Exhibit 4(b);
             Registration Statement No. 33-50229, Exhibits 4(b) and 4(c);
             Registration Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and
             4(e); Registration Statement No. 333-01049, Exhibits 4(b) and
             4(c); Form 8-K, dated March 18, 1996, File No. 1-3457, Exhibit 4].
  10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and
             United States of America, acting by and through the United States
             Atomic Energy Commission, and, subsequent to January 18, 1975, the
             Administrator of the Energy Research and Development
             Administration, as amended [Registration Statement No. 2-60015,
             Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
             5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
             5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
             5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year
             ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and
             Annual Report on Form 10-K of APCo for the fiscal year ended
             December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
  10(a)(2) - Copy of Inter-Company Power Agreement, dated as of July 10, 1953,
             among OVEC and the Sponsoring Companies, as amended [Registration
             Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-
             67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo
             for the fiscal year ended December 31, 1992, File No. 1-3457,
             Exhibit 10(a)(2)(B)].
  10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and
             Indiana-Kentucky Electric Corporation, as amended [Registration
             Statement No. 2-60015, Exhibit 5(e)].
  10(b)    - Copy of Interconnection Agreement, dated July 6, 1951, among APCo,
             CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as
             amended [Registration Statement No. 2-52910, Exhibit 5(a);
             Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on
             Form 10-K of AEP for the fiscal year ended December 31, 1990, File
             No. 1-3525, Exhibit 10(a)(3)].
  10(c)    - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
             CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent,
             as amended [Annual Report on Form 10-K of AEP for the fiscal year
             ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual
             Report on Form 10-K of AEP for the fiscal year ended December 31,
             1988, File No. 1-3525, Exhibit 10(b)(2)].
  10(d)    - Copy of AEP System Interim Allowance Agreement, dated July 28,
             1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service
             Corporation [Annual Report on Form 10-K of APCo for the fiscal
             year ended December 31, 1994, File No. 1-3457, Exhibit 10(d)].
 <dagger>10(e)(1)-AEP Deferred Compensation Agreement for certain executive
             officers [Annual Report on Form 10-K of AEP for the fiscal year
             ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].
 <dagger>10(e)(2)-Amendment to AEP Deferred Compensation Agreement for certain
             executive officers [Annual Report on Form 10-K of AEP for the
             fiscal year ended December 31, 1986, File No. 1-3525, Exhibit
             10(d)(2)].

APCO<double-dagger> (continued)

EXHIBIT NUMBER                                       DESCRIPTION

 <dagger>10(f)(1)-Management Incentive Compensation Plan [Annual Report on Form
             10-K of AEP for the fiscal year ended December 31, 1995, File No.
             1-3525, Exhibit 10(i)(1)].
 <dagger>10(f)(2)-American Electric Power System Performance Share Incentive
             Plan [Quarterly Report on Form 10-Q of APCo for the quarterly
             period ended September 30, 1995, File No. 1-3457, Exhibit 10].
 <dagger>10(g)(1)-Excess Benefits Plan [Annual Report on Form 10-K of AEP for
             the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit
             10(g)(1)(A)].
 <dagger>10(g)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual
             Report on Form 10-K of AEP for the fiscal year ended December 31,
             1993, File No. 1-3525, Exhibit 10(g)(2)].
 <dagger>10(g)(3)-Umbrella Trust<trademark> for Executives [Annual Report on
             Form 10-K of AEP for the fiscal year ended December 31, 1993, File
             No. 1-3525, Exhibit 10(g)(3)].
 <dagger>10(h)(1)-Employment Agreement between E. Linn Draper, Jr. and AEP and
             the Service Corporation [Annual Report on Form 10-K of AEGCo for
             the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit
             10(g)(3)].
 *12       - Statement re: Computation of Ratios.
 *13       - Copy of those portions of the APCo 1995 Annual Report (for the
             fiscal year ended December 31, 1995) which are incorporated by
             reference in this filing.
  21       - List of subsidiaries of APCo [Annual Report on Form 10-K of AEP
             for the fiscal year ended December 31, 1995, File No. 1-3525,
             Exhibit 21].
 *23       - Consent of Deloitte & Touche LLP.
 *24       - Power of Attorney.
 *27       - Financial Data Schedules.


CSPCO<double-dagger>

   3(a)    - Copy of Amended Articles of Incorporation of CSPCo, as amended to
             March 6, 1992 [Registration Statement No. 33-53377, Exhibit 4(a)].
   3(b)    - Copy of Certificate of Amendment to Amended Articles of
             Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form
             10-K of CSPCo for the fiscal year ended December 31, 1994, File
             No. 1-2680, Exhibit 3(b)].
   3(c)    - Composite copy of Amended Articles of Incorporation of CSPCo, as
             amended [Annual Report on Form 10-K of CSPCo for the fiscal year
             ended December 31, 1994, File No. 1-2680, Exhibit 3(c)].
   3(d)    - Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on
             Form 10-K of CSPCo for the fiscal year ended December 31, 1987,
             File No. 1-2680, Exhibit 3(d)].
   4(a)    - Copy of Indenture of Mortgage and Deed of Trust, dated September
             1, 1940, between CSPCo and City Bank Farmers Trust Company (now
             Citibank, N.A.), as trustee, as supplemented and amended
             [Registration Statement No. 2-59411, Exhibits 2(B) and 2(C);
             Registration Statement No. 2-80535, Exhibit 4(b); Registration
             Statement No. 2-87091, Exhibit 4(b); Registration Statement No. 2-
             93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit
             4(b); Registration Statement No. 33-7081, Exhibit 4(b);
             Registration Statement No. 33-12389, Exhibit 4(b); Registration
             Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h);
             Registration Statement No. 33-35651, Exhibit 4(b); Registration
             Statement No. 33-46859, Exhibits 4(b) and 4(c); Registration
             Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration
             Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration
             Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on
             Form 10-K of CSPCo for the fiscal year ended December 31, 1993,
             File No. 1-2680, Exhibit 4(b)].
  10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and
             United States of America, acting by and through the United States
             Atomic Energy Commission, and, subsequent to January 18, 1975, the
             Administrator of the Energy Research and Development
             Administration, as amended [Registration Statement No. 2-60015,
             Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
             5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
             5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
             5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal year
             ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and
             Annual Report on Form 10-K of APCo for the fiscal year ended
             December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
  10(a)(2) - Copy of Inter-Company Power Agreement, dated July 10, 1953, among
             OVEC and the Sponsoring Companies, as amended [Registration
             Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-
             67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo
             for the fiscal year ended December 31, 1992, File No. 1-3457,
             Exhibit 10(a)(2)(B)].
<PAGE>
CSPCO<double-dagger> (continued)

EXHIBIT NUMBER                                       DESCRIPTION

  10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and
             Indiana-Kentucky Electric Corporation, as amended [Registration
             Statement No. 2-60015, Exhibit 5(e)].
  10(b)    - Copy of Interconnection Agreement, dated July 6, 1951, among APCo,
             CSPCo, KEPCo, OPCo and I&M and the Service Corporation, as amended
             [Registration Statement No. 2-52910, Exhibit 5(a); Registration
             Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-
             K of AEP for the fiscal year ended December 31, 1990, File No. 1-
             3525, Exhibit 10(a)(3)].
  10(c)    - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
             CSPCo, I&M, KEPCo, OPCo, and with the Service Corporation as
             agent, as amended [Annual Report on Form 10-K of AEP for the
             fiscal year ended December 31, 1985, File No. 1-3525, Exhibit
             10(b); and Annual Report on Form 10-K of AEP for the fiscal year
             ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
  10(d)    - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of
             APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
             Exhibit 10(d)].
 *12       - Statement re: Computation of Ratios.
 *13       - Copy of those portions of the CSPCo 1995 Annual Report (for the
             fiscal year ended December  31, 1995) which are incorporated by
             reference in this filing.
 *23       - Consent of Deloitte & Touche LLP.
 *24       - Power of Attorney.
 *27       - Financial Data Schedules.


I&M<double-dagger>

   3(a)    - Copy of the Amended Articles of Acceptance of I&M and amendments
             thereto [Annual Report on Form 10-K of I&M for fiscal year ended
             December 31, 1993, File No. 1-3570, Exhibit 3(a)].
   3(b)    - Composite Copy of the Amended Articles of Acceptance of I&M, as
             amended [Annual Report on Form 10-K of I&M for fiscal year ended
             December 31, 1993, File No. 1-3570, Exhibit 3(b)].
  *3(c)    - Copy of the By-Laws of I&M (amended as of January 1, 1996).
   4(a)    - Copy of Mortgage and Deed of Trust, dated as of June 1, 1939,
             between I&M and Irving Trust Company (now The Bank of New York)
             and various individuals, as Trustees, as amended and supplemented
             [Registration Statement No. 2-7597, Exhibit 7(a); Registration
             Statement No. 2-60665, Exhibits 2(c)(2), 2(c)(3), 2(c)(4),
             2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11),
             2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), (2)(c)(16), and 2(c)(17);
             Registration Statement No. 2-63234, Exhibit 2(b)(18); Registration
             Statement No. 2-65389, Exhibit 2(a)(19); Registration Statement
             No. 2-67728, Exhibit 2(b)(20); Registration Statement No. 2-85016,
             Exhibit 4(b); Registration Statement No. 33-5728, Exhibit 4(c);
             Registration Statement No. 33-9280, Exhibit 4(b); Registration
             Statement No. 33-11230, Exhibit 4(b); Registration Statement No.
             33-19620, Exhibits 4(a)(ii), 4(a)(iii), 4(a)(iv) and 4(a)(v);
             Registration Statement No. 33-46851, Exhibits 4(b)(i), 4(b)(ii)
             and 4(b)(iii); Registration Statement No. 33-54480, Exhibits
             4(b)(i) and 4(b)(ii); Registration Statement No. 33-60886, Exhibit
             4(b)(i); Registration Statement No. 33-50521, Exhibits 4(b)(i),
             4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K of I&M for
             fiscal year ended December 31, 1993, File No. 1-3570, Exhibit
             4(b); Annual Report on Form 10-K of I&M for fiscal year ended
             December 31, 1994, File No. 1-3570, Exhibit 4(b)].
  10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and
             United States of America, acting by and through the United States
             Atomic Energy Commission, and, subsequent to January 18, 1975, the
             Administrator of the Energy Research and Development
             Administration, as amended [Registration Statement No. 2-60015,
             Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
             5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
             5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
             5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year
             ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and
             Annual Report on Form 10-K of APCo for the fiscal year ended
             December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
  10(a)(2) - Copy of Inter-Company Power Agreement, dated as of July 10, 1953,
             among OVEC and the Sponsoring Companies, as amended [Registration
             Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-
             67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for
             the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit
             10(a)(2)(B)].
  10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and
             Indiana-Kentucky Electric Corporation, as amended [Registration
             Statement No. 2-60015, Exhibit 5(e)].
<PAGE>
I&M<double-dagger> (continued)

EXHIBIT NUMBER                                       DESCRIPTION

  10(b)    - Copy of Interconnection Agreement, dated July 6, 1951, between
             APCo, CSPCo, KEPCo, I&M, and OPCo and with the Service
             Corporation, as amended [Registration Statement No. 2-52910,
             Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b);
             and Annual Report on Form 10-K of AEP for the fiscal year ended
             December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
  10(c)    - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
             CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent,
             as amended [Annual Report on Form 10-K of AEP for the fiscal year
             ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and
             Annual Report on Form 10-K of AEP for the fiscal year ended
             December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
  10(d)    - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of
             APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
             Exhibit 10(d)].
  10(e)    - Copy of Nuclear Material Lease Agreement, dated as of December 1,
             1990, between I&M and DCC Fuel Corporation [Annual Report on Form
             10-K of I&M for the fiscal year ended December 31, 1993, File No.
             1-3570, Exhibit 10(d)].
  10(f)    - Copy of Lease Agreements, dated as of December 1, 1989, between
             I&M and Wilmington Trust Company, as amended [Registration
             Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C),
             28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); Annual
             Report on Form 10-K of I&M for the fiscal year ended December 31,
             1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B),
             10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
 *12       - Statement re: Computation of Ratios
 *13       - Copy of those portions of the I&M 1995 Annual Report (for the
             fiscal year ended December 31, 1995) which are incorporated by
             reference in this filing.
 21        - List of subsidiaries of I&M [Annual Report on Form 10-K of AEP for
             the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit
             21].
 *23       - Consent of Deloitte & Touche LLP.
 *24       - Power of Attorney.
 *27       - Financial Data Schedules.


KEPCO

   3(a)    - Copy of Restated Articles of Incorporation of KEPCo [Annual Report
             on Form 10-K of KEPCo for the fiscal year ended December 31, 1991,
             File No. 1-6858, Exhibit 3(a)].
  *3(b)    - Copy of By-Laws of KEPCo (amended as of January 1, 1996).
   4(a)    - Copy of Mortgage and Deed of Trust, dated May 1, 1949, between
             KEPCo and Bankers Trust Company, as supplemented and amended
             [Registration Statement No. 2-65820, Exhibits 2(b)(1), 2(b)(2),
             2(b)(3), 2(b)(4), 2(b)(5), and  2(b)(6); Registration Statement
             No. 33-39394, Exhibits 4(b) and 4(c); Registration Statement No.
             33-53226, Exhibits 4(b) and 4(c); Registration Statement No. 33-
             61808, Exhibits 4(b) and 4(c), Registration Statement No. 33-
             53007, Exhibits 4(b), 4(c) and 4(d)].
  10(a)    - Copy of Interconnection Agreement, dated July 6, 1951, among APCo,
             CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as
             amended [Registration Statement No. 2-52910, Exhibit 5(a);
             Registration Statement No. 2-61009, Exhibit 5(b); and Annual
             Report on Form 10-K of AEP for the fiscal year ended December 31,
             1990, File No. 1-3525, Exhibit 10(a)(3)].
  10(b)    - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
             CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent,
             as amended [Annual Report on Form 10-K of AEP for the fiscal year
             ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and
             Annual Report on Form 10-K of AEP for the fiscal year ended
             December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
  10(c)    - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of
             APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
             Exhibit 10(d)].
 *12       - Statement re: Computation of Ratios.
 *13       - Copy those portions of the KEPCo 1995 Annual Report (for the
             fiscal year ended December 31, 1995) which are incorporated by
             reference in this filing.
 *23       - Consent of Deloitte & Touche LLP.
 *24       - Power of Attorney.
 *27       - Financial Data Schedules.
<PAGE>
OPCO<double-dagger>

EXHIBIT NUMBER                                       DESCRIPTION

   3(a)    - Copy of Amended Articles of Incorporation of OPCo, and amendments
             thereto to December 31, 1993 [Registration Statement No. 33-50139,
             Exhibit 4(a); Annual Report on Form 10-K of OPCo for the fiscal
             year ended December 31, 1993, File No. 1-6543, Exhibit 3(b)].
   3(b)    - Certificate of Amendment to Amended Articles of Incorporation of
             OPCo, dated May 3, 1994 [Annual Report on Form 10-K of OPCo for
             the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit
             3(b)].
   3(c)    - Composite copy of the Amended Articles of Incorporation of OPCo,
             as amended [Annual Report on Form 10-K of OPCo for the fiscal year
             ended December 31, 1994, File No. 1-6543, Exhibit 3(c)].
   3(d)    - Copy of Code of Regulations of OPCo [Annual Report on Form 10-K of
             OPCo for the fiscal year ended December 31, 1990, File No. 1-6543,
             Exhibit 3(d)].
   4(a)    - Copy of Mortgage and Deed of Trust, dated as of October 1, 1938,
             between OPCo and Manufacturers Hanover Trust Company (now Chemical
             Bank), as Trustee, as amended and supplemented [Registration
             Statement No. 2-3828, Exhibit B-4; Registration Statement No. 2-
             60721, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6),
             2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13),
             2(c)(14), 2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19),
             2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25),
             2(c)(26), 2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31);
             Registration Statement No. 2-83591, Exhibit 4(b); Registration
             Statement No. 33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(vi);
             Registration Statement No. 33-31069, Exhibit 4(a)(ii);
             Registration Statement No. 33-44995, Exhibit 4(a)(ii);
             Registration Statement No. 33-59006, Exhibits 4(a)(ii), 4(a)(iii)
             and 4(a)(iv); Registration Statement No. 33-50373, Exhibits
             4(a)(ii), 4(a)(iii) and 4(a)(iv); Annual Report on Form 10-K of
             OPCo for the fiscal year ended December 31, 1993, File No. 1-6543,
             Exhibit 4(b)].
  10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and
             United States of America, acting by and through the United States
             Atomic Energy Commission, and, subsequent to January 18, 1975, the
             Administrator of the Energy Research and Development
             Administration, as amended [Registration Statement No. 2-60015,
             Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
             5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
             5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
             5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year
             ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F);
             Annual Report on Form 10-K of APCo for the fiscal year ended
             December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
  10(a)(2) - Copy of Inter-Company Power Agreement, dated July 10, 1953, among
             OVEC and the Sponsoring Companies, as amended [Registration
             Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-
             67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo  for
             the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit
             10(a)(2)(B)].
  10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and
             Indiana-Kentucky Electric Corporation, as amended [Registration
             Statement No. 2-60015, Exhibit 5(e)].
  10(b)    - Copy of Interconnection Agreement, dated July 6, 1951, between
             APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation,
             as amended [Registration Statement No. 2-52910, Exhibit 5(a);
             Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on
             Form 10-K of AEP for the fiscal year ended December 31, 1990, File
             1-3525, Exhibit 10(a)(3)].
  10(c)    - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
             CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent
             [Annual Report on Form 10-K of AEP for the fiscal year ended
             December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report
             on Form 10-K of AEP for the fiscal year ended December 31, 1988,
             File No. 1-3525, Exhibit 10(b)(2)].
  10(d)    - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of
             APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
             Exhibit 10(d)].
  10(e)    - Copy of Agreement, dated June 18, 1968, between OPCo and Kaiser
             Aluminum & Chemical Corporation (now known as Ravenswood Aluminum
             Corporation) and First Supplemental Agreement thereto
             [Registration Statement No. 2-31625, Exhibit 4(c); Annual Report
             on Form 10-K of OPCo for the fiscal year ended December 31, 1986,
             File No. 1-6543, Exhibit 10(d)(2)].
  10(f)    - Copy of Power Agreement, dated November 16, 1966, between OPCo and
             Ormet Generating Corporation and First Supplemental Agreement
             thereto [Annual Report on Form 10-K of OPCo for the fiscal year
             ended December 31, 1993, File No. 1-6543, Exhibit 10(e)].
  10(g)    - Copy of Amendment No. 1, dated October 1, 1973, to Station
             Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal
             Operating Company, and amendments thereto [Annual Report
<PAGE>
OPCO<double-dagger> (continued)

EXHIBIT NUMBER                                       DESCRIPTION

             on Form 10-K of OPCo for the fiscal year ended December 31, 1993,
             File No. 1-6543, Exhibit 10(f)].
 <dagger>10(h)(1)-AEP Deferred Compensation Agreement for certain executive
             officers [Annual Report on Form 10-K of AEP for the fiscal year
             ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].
 <dagger>10(h)(2)-Amendment to AEP Deferred Compensation Agreement for certain
             executive officers [Annual Report on Form 10-K of AEP for the
             fiscal year ended December 31, 1986, File No. 1-3525, Exhibit
             10(d)(2)].
 <dagger>10(i)(1)-Management Incentive Compensation Plan [Annual Report on Form
             10-K of AEP for the fiscal year ended December 31, 1995, File No.
             1-3525, Exhibit 10(i)(1)].
 <dagger>10(i)(2)-American Electric Power System Performance Share Incentive
             Plan, as Amended and Restated through January 1, 1995 [Quarterly
             Report on Form 10-Q of OPCo for the quarterly period ended
             September 30, 1995, File No. 1-6543].
 <dagger>10(j)(1)-Excess Benefits Plan [Annual Report on Form 10-K of AEP for
             the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit
             10(g)(1)(A)].
 <dagger>10(j)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual
             Report on Form 10-K of AEP for the fiscal year ended December 31,
             1993, File No. 1-3525, Exhibit 10(g)(2)].
 <dagger>10(j)(3)-Umbrella Trust<trademark> for Executives [Annual Report on
             Form 10-K of AEP for the fiscal year ended December 31, 1993, File
             No. 1-3525, Exhibit 10(g)(3)].
 <dagger>10(k)(1)-Employment Agreement between E. Linn Draper, Jr. and AEP and
             the Service Corporation [Annual Report on Form 10-K of AEGCo for
             the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit
             10(g)(2)].
  10(l)(1) - Agreement for Lease dated as of September 17, 1992 between JMG
             Funding, Limited Partnership and OPCo [Annual Report on Form 10-K
             of OPCo for the fiscal year ended December 31, 1992, File No. 1-
             6543, Exhibit 10(l)].
  10(l)(2) - Lease Agreement dated January 20, 1995 between OPCo and JMG
             Funding, Limited Partnership, and amendment thereto (confidential
             treatment requested) [Annual Report on Form 10-K of OPCo for the
             fiscal year ended December 31, 1994, File No. 1-6543, Exhibit
             10(l)(2)].
 *12       - Statement re: Computation of Ratios.
 *13       - Copy of those portions of the OPCo 1995 Annual Report (for the
             fiscal year ended December 31, 1995) which are incorporated by
             reference in this filing.
  21       - List of subsidiaries of OPCo [Annual Report on Form 10-K of AEP
             for the fiscal year ended December 31, 1995, File No. 1-3525,
             Exhibit 21].
 *23       - Consent of Deloitte & Touche LLP.
 *24       - Power of Attorney.
 *27       - Financial Data Schedules.



<double-dagger>Certain instruments defining the rights of holders of long-term
debt of the registrants included in the financial statements of registrants
filed herewith have been omitted because the total amount of securities
authorized thereunder does not exceed 10% of the total assets of registrants.
The registrants hereby agree to furnish a copy of any such omitted instrument
to the SEC upon request.